Microsoft Word - R06-25 081806 morning hearing transcript

1104

ILLINOIS POLLUTION CONTROL BOARD

August 18, 2006

3 IN THE MATTER OF:

)

5 PROPOSED NEW 35 ILL. ADM. CODE 225) R06-25

6 CONTROL OF EMISSIONS FROM LARGE ) (Rulemaking-Air)

7 COMBUSTION SOURCES (MERCURY)

)

TRANSCRIPT OF PROCEEDINGS held in the

10 above-entitled cause before Hearing Officer

11 Marie E. Tipsord, called by the Illinois Pollution

12 Control Board, pursuant to notice, taken before

13 Sharon Berkery, CSR, a notary public within and for

14 the County of Cook and State of Illinois, at the

15 James R. Thompson Center, 100 West Randolph Street,

16 Assembly Hall, Chicago, Illinois, on the 18th day of

17 August, A.D., 2006, commencing at 9:00 a.m.

L.A. REPORTING (312) 419-9292

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1 A P P E A R A N C E S:

ILLINOIS POLLUTION CONTROL BOARD:

Ms. Marie Tipsord, Hearing Officer

Ms. Andrea S. Moore, Board Member

Mr. G. Tanner Girard, Acting Chairman, IPCB

Mr. Anand Rao, Senior Environmental Scientist

Mr. Nicholas J. Melas, Board Member

Mr. Timothy J. Fox, Board Member

ILLINOIS ENVIRONMENTAL PROTECTION AGENCY:

Mr. John J. Kim

Mr. Charles E. Matoesian

Mr. James Staudt

Mr. Richard Ayres

SCHIFF, HARDIN, LLP,

6600 Sears Tower

Chicago, Illinois 60606

312-258-5646

BY: MS. KATHLEEN C. BASSI

MR. STEPHEN J. BONEBRAKE

MR. SHELDON A. ZABEL

L.A. REPORTING (312) 419-9292

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1 A P P E A R A N C E S (cont'd):

ENVIRONMENTAL LAW PROGRAM, CHICAGO LEGAL CLINIC

205 West Monroe Street

Fourth Floor

Chicago, Illinois 60606

312-726-2938

BY: MR. KEITH I. HARLEY,

SORBENT TECHNOLOGIES CORPORATION

1664 East Highland Road

Twinsburg, Ohio 44087

330-425-2354

BY: MR. SID NELSON, JR.

23 REPORTED BY: SHARON BERKERY, C.S.R.

CERTIFICATE NO. 84-4327.

L.A. REPORTING (312) 419-9292

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HEARING OFFICER: Good morning.

Welcome everyone back.

This is day five. And hopefully

this is going to be a short day for us.

We are going to start with

Mr. DePriest, who was sworn in yesterday. But

before we do that, I'm going to formally ask on

the record, because we have been discussing on

and off the record, the Stubenville study.

Mr. Kim, do you have an update on

where you may be, as far as being able to

present something on the Stubenville study?

MR. KIM: I can describe for you the

efforts we have taken thus far to obtain that.

We had asked Dr. Keeler as to the status of the

report.

The last word that we had from him

was in the middle or late part of July, at which

time he indicated the manuscript or document had

been forwarded to the environmental science and

technology publisher, I don't know if it's

completely an online publishing entity, but it

had been sent on to the publisher; and that the

word he received from the publisher was that it

L.A. REPORTING (312) 419-9292

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would be two to three weeks before it was made

available online.

We have been, since that time,

checking on a daily basis to see if, in fact, it

had been made available. And I checked last

night -- I didn't get a chance to check this

morning, but as of 10:00 last night, it was not

yet available.

We have asked our librarian at the

Illinois EPA to contact the publisher to see if

she can either get a definite publication date

or, at the very least, if it's all but published

and if it's in a que waiting to be published, if

we could just see if we can get a draft of the

document that is going to be published.

Because, I'm assuming, at this point, no further

changes are going to be made to the document.

So, again, I apologize for the

delay. And, frankly, this is something that we

really had hoped we would have had a long time

ago. But based upon what Dr. Keeler told us, as

of about July 15 or July 20, it was out of his

hands and it was now into the publisher's hands.

And so, now we're trying to work

L.A. REPORTING (312) 419-9292

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on the publishers to see if we can get something

there. If we don't hear back from the publisher

right way, then my guess is that early next week

we would potentially try and contact somebody at

U.S.EPA, perhaps, and Dr. Keeler's counterparts

there and see if maybe we could get a draft from

them.

Or we'll try again with

Dr. Keeler. He's a very busy man and very

difficult to reach sometimes, and, over the past

week, we've had a little bit of difficulty

communicating with him.

So we're going to try and -- we

sent another e-mail to him and left some

messages again this morning, I believe, trying

to get ahold of him, asking if he knows where

things are. Or, at the very least, if he knows

no more changes are going to be made, if he

could send us a copy so that we can make it

available to you.

At this point, I think there's --

I can't imagine there's any more changes that

are going to be made to this document. I think

it's a done document. And the impression I'm

L.A. REPORTING (312) 419-9292

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left with is just waiting for its turn to make

it online.

But we will continue to try, and

we will give you an update next Monday to let

you know if it's changed over the weekend.

HEARING OFFICER: Thank you, Mr. Kim.

MR. BONEBRAKE: Can I just ask a

follow-up question?

HEARING OFFICER: Absolutely.

MR. BONEBRAKE: There was also an

issue, I believe, Mr. Kim, pertaining to a

document that U.S.EPA had provided to

Dr. Keeler. I don't recall the specifics since

the passage of time, but my recollection was it

was a significant number of pages of documents.

Do you know what the status on the

disclosure of that document is?

MR. KIM: Yes. We asked Dr. Keeler

about that.

And my understanding is -- the way

he described it to me, that it is not something

that he believed U.S.EPA would ever authorize

him to release, because it would be an integral

part of their peer review system. I don't know

L.A. REPORTING (312) 419-9292

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if the comments contained the identities of the

parties who were making the comments or if it's

a blind set of comments that he received, just

simply comment after comment after comment.

But the response we got from him

was that he just did not foresee a possibility

that he would ever be authorized to allow that,

because -- something about, based upon the

understanding that he has and other people have

with U.S.EPA when they perform these types of

joint studies -- peer publications, U.S.EPA peer

review comments. His representation to me was,

they're just never made public.

I kind of pressed him a little bit

on it, and -- as opposed to the Stubenville

study, which I think he has said all along, he

would be more than happy to have made public as

soon as it's made available -- this document he

seemed to indicate he would not be able to get

free from the U.S.EPA in terms of authorization

to release.

MR. BONEBRAKE: Does that mean,

therefore, that the document, you anticipate,

would not become part of the Board record in

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this proceeding?

MR. KIM: Based upon my conversation

with him, I think that's correct. But we're

hoping that the final document itself will,

obviously, be made available just as quickly as

possible.

HEARING OFFICER: Thank you, Mr. Kim.

With that, I believe,

Mr. DePriest, we're on Question No. 11.

MR. DePRIEST: Question No. 11.

Regarding the statement on Page 9, "For units

that plan to install a wet FGD system in the

future for CAIR compliance, a smaller

'polishing' fabric filter could be needed in

2009 to meet the proposed Illinois Rule" and the

following discussion regarding associated costs,

why would a company install a fabric filter

rather than inject sorbent upstream of the

existing ESP, if the emissions levels of the

Illinois Rule were achievable in that manner?

Wouldn't that approach be far less expensive?

My answer: As discussed in the

response to Question 10.a -- I'll have to go

back to yesterday -- 90 percent reduction may

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not be achievable with capture in the existing

ESP, based on ESP size and concerns about

additional particulate emissions.

HEARING OFFICER: Mr. DePriest, could

you slow down?

MR. BONEBRAKE: Are people able to

hear?

HEARING OFFICER: Can you hear okay

out there?

MR. BONEBRAKE: Okay.

MR. DePRIEST: Where was I?

In addition, activated carbon

system suppliers, to date, have been unwilling

to unilaterally offer a guarantee of 90 percent

removal in ESP without the addition of a

baghouse.

Just adding another comment to

directly answer the question, certainly, if we

could do it in the ESP, it would be a heck of a

lot cheaper than in the baghouse, with activated

carbon injection.

HEARING OFFICER: And you are fading.

Let's plug in the mic and maybe leave it out

there at the edge.

L.A. REPORTING (312) 419-9292

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Okay. Let's try that.

MR. DePRIEST: Question No. 12.

Regarding the statement on Page 10, "The owners

of the Illinois coal-fired units have reached

the conclusion that they will not be able to

meet the requirements of the proposed Illinois

mercury with activated carbon injection alone,

at most units, based on the lack of precipitator

margin."

Have the owners of these plants

performed any tests of sorbent to base their

opinions? If not, with the federal and state

regulations on the way, why not?

My answer: Testing of activated

carbon injection upstream of existing ESPs has

been performed on a significant number of units

in the industry. This testing is the basis for

our concerns about the capability of all ESPs to

be capable of 90 percent mercury capture without

an adverse opacity or particulate emissions or

both.

S&L was not directly involved in

the testing, and therefore, does not have the

ability to share the specifics, although this

L.A. REPORTING (312) 419-9292

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information is probably available from the

funding parties.

HEARING OFFICER: Mr. Kim.

MR. KIM: Yes.

When you say the owners of the

Illinois coal-fired units, can you be more

definitive as to which owners you're referring

to?

MR. DePRIEST: The owners that we

worked for?

MR. KIM: Well, whatever owners you

were referring to in that statement.

MR. DePRIEST: I guess it would be the

companies -- the units associated with the

companies of Midwest Gen, Dominion and Ameren.

MR. KIM: Thank you.

MR. DePRIEST: Question No. 13. What

analysis of their ESPs have the companies

performed to reach their conclusion?

And, with that, I need to refer

you back to my answer to Question No. 6, to be

consistent. And my answer to that was, in

general, our analysis of the capabilities of the

existing ESPs to accommodate activated carbon

L.A. REPORTING (312) 419-9292

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injection was performed on a qualitative basis,

considering the existing ESP size and the

current emission rates and opacity.

More importantly, any particulate

increase in the inlet loading of the ESP will

result in an increase in the outlet mode, which

will impact the emission rate and the opacity.

Question No. 14. Regarding the

statement on Page 10, "In addition, suppliers of

the activated carbon technology are currently

not willing to guarantee 90 percent mercury

removal with activated carbon injection alone."

Has your client performed any testing with any

company to potentially provide guarantees?

Again, I need to refer back to

Question No. 12, which I just answered, with the

added caveat of: We are aware of test results

obtained in the industry that clearly support

the conclusion that a 90 percent mercury

reduction cannot be obtained in all the ESP's in

the Illinois units with activated carbon

injection alone without adverse effects on

opacity or particulate emissions or both. In

our discussions with companies that provide

L.A. REPORTING (312) 419-9292

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mercury reduction technologies, they concur with

these conclusions, and in fact, will not provide

unilateral guarantees of 90 percent reduction

for ACI with ESP applications.

HEARING OFFICER: Mr. Bonebrake.

MR. RAO: I have a comment.

HEARING OFFICER: Okay. Go ahead.

MR. RAO: Mr. DePriest, do you have

the list of the names of these companies that

you got this information from, about not

providing the guarantees?

MR. DePRIEST: Yes, I can offer those

names. Most prominently is the ADA-ES. But

second tier companies would be like Babcox &

Wilcox, Wheel Grater, Destex -- equipment

suppliers that would attach an activated carbon

injection system to their system and then pass

the guarantees through to the ultimate owner.

MR. RAO: Thank you.

HEARING OFFICER: Mr. Nelson.

MR. NELSON: Are you aware that

Sorbent Technologies has guaranteed --

HEARING OFFICER: Excuse me,

Mr. Nelson, you need to identify yourself for

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the court reporter.

MR. NELSON: I'm sorry.

I'm Sid Nelson, Sorbent

Technologies.

Are you aware that Sorbent

Technologies has guaranteed 90 percent?

MR. DePRIEST: I've heard rumors to

that effect. Sorbent Technologies has not

approached Sargent & Lundy with such guarantees

that I am aware of.

MR. NELSON: Has Sargent & Lundy ever

required it from Sorbent Technologies?

MR. DePRIEST: We, typically, would be

looking for the guarantees to come from the

equipment supplier, either via, C, fabric

filter, dry scrubber, wet scrubber supplier, who

would then attach a sorbent injection technology

to their offering and then give us the

guarantees to pass through from the designer of

the activated carbon injection system.

MR. NELSON: In the case where the

material itself is sorbent, is critical to

achieving 90 percent or not and where the

guarantee could provide more sorbent, for

L.A. REPORTING (312) 419-9292

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example, as to a guarantee of a certain rate,

would it not make sense to put a guarantee upon

the sorbent supplier?

MR. DePRIEST: In our opinion, we --

it may make sense in some cases, and maybe, in

particular, when dealing with an existing ESP

and that all you're purchasing is an injection

system of the sorbent. But when we're

purchasing a much larger piece of equipment that

might be doing some of the mercury reduction

itself, we would prefer to have that company,

who has a lot more skin in the game, so to

speak, to be a party to that guarantee.

So the guarantee becomes much more

meaningful if we have a $100 million FGD

contract attached to that guarantee than a $1

million activated carbon injection system

attached to that, if you understand what I mean.

MR. NELSON: That's why a guarantee is

so difficult for wet scrubbers, for example.

But for the installation simply of only an

activated carbon injection system, does it make

sense for the equipment supplier that has no

control over the actual sorbents that are used,

L.A. REPORTING (312) 419-9292

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to guarantee the 90 percent?

MR. DePRIEST: We want them to have

control over the sorbents that are used, because

we want the guarantee to come from them. So

it's incumbent upon them to research the

available sorbents in the industry, including

yours, find the one that's most appropriate for

the application that we are asking for it to be

applied to and pass that guarantee to us.

MR. NELSON: So, in your contracts,

you would recommend the long-term sorbent supply

contract be part of any activated carbon

injection system installation?

MR. DePRIEST: It might have some

attractive features to it, but, to date, we have

not found a way to make that happen, to attach a

long-term sorbent injection supply contract to

the supply of the original equipment. It might

be good to do that, but I think most utilities

would like to have the ability to shop the

sorbent down the road.

Let's say, five or ten years from

now a new sorbent appears on the scene that

maybe is not yours, Mr. Nelson, and the company

L.A. REPORTING (312) 419-9292

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would like the flexibility to jump over to that

if it made sense. So the long-term contract for

sorbent has its pluses and minuses.

MR. NELSON: But if there is going to

be flexibility, which might be very good, how

would you expect the equipment supplier, the

injection system to guarantee 90 percent if

there is no long-term contract with the sorbent?

MR. DePRIEST: Well, you have to

understand that the guarantees -- the typical

guarantees are the ones that I'm familiar

with -- the actual performance of that injection

system is demonstrated in a very short period of

time. That guy's paid, he's gone, his

responsibilities are done.

It's now the owner's

responsibility to operate and maintain that

equipment to achieve the requirements of

whatever his permit might be. The equipment

supplier is no longer involved with that.

MR. NELSON: Thank you.

HEARING OFFICER: Mr. Harley has a

follow-up.

Go ahead, Mr. Harley.

L.A. REPORTING (312) 419-9292

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MR. HARLEY: For the record, Keith

Harley, on behalf of Environment Illinois. Good

morning.

You used a phrase that I didn't

understand. You said you'd prefer to obtain a

guarantee from a vendor which has, you said, a

lot more something in the game. What was that

phrase?

MR. DePRIEST: I probably shouldn't

have said that -- who has a lot more investment,

capital investment, let's say, in the project.

So if you look at guarantees and how they're

typically structured, the remedies that an

equipment supplier might have available to him

will be a function of his contract talks.

So, in many cases, limits of his

liability will be a function of that contract

cost. So if I get a guarantee from someone who

has $100 million scrubber project attached to

that guarantee, I have a lot more security with

him, than somebody who has got a million dollar

injection system.

MR. HARLEY: So is it your testimony

that there are no guarantees available? Or is

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it your testimony that Sargent & Lundy has made

a business decision that expresses certain

preferences as to what a guarantee should be?

MR. DePRIEST: I'm not sure I

understand that. I mean, we try to structure

our guarantees, both performance and technical

and commercial, to protect the owner from his

investment, protecting the investment that he's

making, that technology. So I'm not sure where

you're going.

MR. HARLEY: May there be -- strike

that.

Could guarantees be available that

would not meet Sargent & Lundy's criteria for

what constitutes an effective guarantee --

MR. DePRIEST: Well, I mean, what an

effective guarantee is, is the guarantee that we

can get. And we, many times, ask for a

guarantee that's in excess of what we are able

to obtain.

And we negotiate to come up with

an agreeable guarantee based on that -- under

those conditions.

MR. HARLEY: Thank you.

L.A. REPORTING (312) 419-9292

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HEARING OFFICER: Mr. Nelson.

MR. NELSON: In the case of a scrubber

that doesn't exist, it takes two years to

build -- to design, build and operate. Would

you say that guarantees of performance are very

important to the utility who buys them?

MR. DePRIEST: Absolutely.

MR. NELSON: With respect to activated

carbon injection, is it possible to run a

short-term trial, with a mobile unit to inject

at the site, with the coal that the utility is

currently burning on the existing ESP, and very

inexpensively, find out if you can get 90

percent at what injection rate at that site?

MR. DePRIEST: Under those typically

static conditions, I think that's achievable.

MR. NELSON: And, in fact, aren't

utilities across the country today having these

couple-week trials of activated carbon injection

into their existing ESPs to see what is

achievable at their actual plants?

MR. DePRIEST: Yes, I think you're

correct.

MR. NELSON: Would it be very simple

L.A. REPORTING (312) 419-9292

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and inexpensive then for power plants that are

concerned about achieving 90 percent mercury

removal to actually do these short-term trials

at their plants to see if, in fact, can we get

90 percent -- can 90 percent be guaranteed at

this plant?

MR. DePRIEST: That's correct. I

think --

MR. NELSON: And you can't do

something like that with a scrubber or SCR; can

you?

MR. DePRIEST: With a scrubber and

SCR -- of course, we've got plenty of them to

look at that are operating out there in the real

world that -- that form the basis of our

establishing the comfort level with the

guarantees that we --

MR. NELSON: But to achieve 98 percent

SO2 removal and 97 percent?

MR. DePRIEST: Uh-huh.

MR. NELSON: Thank you.

HEARING OFFICER: Mr. Bonebrake.

MR. BONEBRAKE: Mr. DePriest, I think

I did have a couple of follow-up questions for

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you. Mr. Nelson was just asking about the

potential for two-week trials of similar

short-term tests.

MR. DePRIEST: Right.

MR. BONEBRAKE: Would the results of a

short-term test like that tell you definitely

whether the unit could achieve long-term

compliance with the mercury standard?

MR. DePRIEST: Certainly, if you could

first step in and establish a comfort level with

the technology, as with any emerging technology,

a long-term operation along with a term of the

more comfort that you get with the technology --

and I think, currently, where we are, at least

Sargent & Lundy in our opinion, is that there is

not enough long-term operating experience with

activated carbon upstream of ESPs and other

components in the industry, to feel very

comfortable about the guarantees that we might

receive.

MR. BONEBRAKE: Moving to a somewhat

different note, there's been a lot of discussion

in the last couple of days regarding the

availability of mercury reduction guarantees.

L.A. REPORTING (312) 419-9292

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And so let me ask you, Mr. DePriest, are you

aware of instances where generating companies

have obtained mercury emission reduction

guarantees?

MR. DePRIEST: Yes, I am. Based on

some of the questions asked yesterday, I decided

I'd go back to the office and do a little

research into some of the specifics of the

projects that we're involved in.

And there's three instances that I

can bring to bear here today where we have

actually secured guarantees for mercury

reduction on full scale utility coal-fire power

plants. And I'll just briefly go through those

three.

One. The first example would be a

large 800-class megawatt super critical unit

that we're currently in design with that we have

secured as part of our contract for the

pollution control equipment on that site, a

50 percent mercury reduction guarantee on a

fabric filter with a dry FGD system in front of

it, using PRB coal with the maximum limitation

of ten pounds per million ACFM inlet activated

L.A. REPORTING (312) 419-9292

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carbon injection rate with the remedies being --

well, I'll first go into the permits that the

particular station has.

HEARING OFFICER: Excuse me. I hate

to interrupt, but I want to be sure that we're

not -- as has been said many times -- mixing

apples and oranges.

MR. DePRIEST: Okay.

HEARING OFFICER: Fifty percent

emission reduction from what, from what's

currently emitted?

MR. DePRIEST: It's a brand new unit.

HEARING OFFICER: Okay.

MR. DePRIEST: From the coal.

HEARING OFFICER: Thank you.

MR. DePRIEST: From the coal. All of

them are oxidized or unoxidized.

HEARING OFFICER: Thank you.

MR. DePRIEST: It's a 50 percent

reduction.

HEARING OFFICER: Thank you. I just

wanted to be sure.

MR. DePRIEST: The permit that the

utility is working to has a mercury emission

L.A. REPORTING (312) 419-9292

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limit of 2.72 pounds per trillion ETU. So,

depending on the fuel that they burn and the

mercury level in the fuel, that could result in

any number of different percent reduction

requirements to achieve the permit level.

But the permit level has a caveat

attached to it. It says that we -- part of your

permit will be to take that activated carbon

injection system that you bought from your

system supplier at 10 pounds per million ACFM

and show us the best it can do.

And they have agreed to modify the

2.72 pounds per trillion emission limit based on

that testing activity. And the remedies that

the equipment supplier has is that he's

guaranteed he'll do at least 50.

I'm sure he'll probably do better

than that, considering the type of technology

we're talking about and the status of the

activated carbon available in the industry. But

that's the guarantee we got, 50 percent

reduction in that particular project, new units.

HEARING OFFICER: Mr. DePriest, excuse

me. I'm assuming you can't tell us who that is,

L.A. REPORTING (312) 419-9292

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but could you tell us please where that plant

is?

MR. DePRIEST: It's in North America.

No, it's in the state of Iowa.

HEARING OFFICER: Thank you.

MR. KIM: And just for clarification,

that's a unit that's in design. So it has not

actually been built?

MR. DePRIEST: That's correct.

Example No. 2 is, we recently

bought five wet FGD systems, limestone based,

for a utility here in the Midwest. Assisted

them in buying it, I should say, they bought the

system.

We obtained from the system

supplier -- this is a wet limestone scrubber,

all of which would be installed, retrofitted to

existing plants, downstream of cold-side ESPs.

We got a 90 percent mercury reduction guarantee

from the FGD system supplier, that he would

capture that in his scrubber himself.

So the precipitator gets

something, that's neither here nor there. He's

going to get 90 on his system, inlet to outlet.

L.A. REPORTING (312) 419-9292

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With the remedy, if it doesn't

work, he has the ability to go in and add fuel

additives to the furnace to change the

speciation of the mercury -- oh, I'll make one

more caveat before I move on. Just to be sure

we're clear, it's 90 percent reduction of the

oxidized mercury coming to it.

So he has the ability to add

additives to the scrubber in case he has a

reintrainment-type or reemission-type of issue

to secure that guarantee or add additives to the

fuel. The case of adding additives to the fuel,

that would be done at the expense of the owner

who is trying to enhance the oxidized portions,

so that the scrubber works harder.

If the system does not work, the

remedy is for the system supplier to supply the

owner with an activated carbon injection system

upstream of the existing cold-side ESP and get

what you got. So if he gets ten percent, he's

clean, he's done.

If he gets 90 percent, everybody's

happy and he's done. That's Example No. 2.

The third example -- and these are

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only three examples where we have, actually, a

firm guarantee for mercury reduction. We help

to assist another client to purchase a fabric

filter with the intent of, in the future, adding

a dry scrubber, but currently, just the fabric

filter, to a coal-fired unit burning PRB.

We asked for 90 percent reduction,

total mercury reduction, they countered with 75,

and that's what we ended up signing the contract

at. Seventy-five percent mercury reduction,

activated carbon injection, upstream of a new

fabric filter, which will operate downstream of

that existing ESP. Those are three guarantees

that we have secured.

Now, the question came up, well,

how about securing guarantees associated with

activated carbon injection upstream of an ESP.

We have had an opportunity -- and I would

clarify my comments yesterday, that I think

might have misled some people.

We have not had an opportunity to

actually ask for such a guarantee formally in a

contract-type of offering, but we have

interviewed activated carbon injection system

L.A. REPORTING (312) 419-9292

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suppliers as to their willingness to offer such

a guarantee. And the example that was presented

to us was a project where the company had

actually injected activated carbon into a unit

that had an ESP of over 400 SEA, did not use SO3

conditioning for particulate collections, had a

very long, in excess, of 100 foot leading up to

cold-side ESP.

Under those conditions and those

caveats, we were told that he would be willing

to offer a 90 percent reduction guarantee for

that type of situation. We made it very clear,

you take away any of those caveats, SEA less

than 400, SO3 injection for particulate control

or not a robust inlet ductwork, all bets are

off. But under those conditions, based on his

testing results, he was willing to up for that

guarantee.

Now, maybe in the future we'll

have a reason to formally ask him for that. And

then we'll see whether or not he'll back that up

with an actual formal guarantee, but that's

what's been offered.

So to clarify my responses

L.A. REPORTING (312) 419-9292

1134

yesterday, hopefully that does that.

MR. BONEBRAKE: One other follow-up.

The guarantees that you've described,

Mr. DePriest, are they a guarantee of long-term

compliance with a particular standard, or do

they address achievement of a particular

standard at a particular point in time?

MR. DePRIEST: They are, for all

practical purposes, a one-time test-type of

guarantee. You set the system up to run under a

certain set of conditions that meet the criteria

of the contract, you test it, it meets 90 or it

doesn't meet 90. It meets 75, he's done,

doesn't meet 75 -- if it passes, he's done.

And now it's the responsibility of

the utility to take that and make it to operate

for the rest of the life of the plan under his

own.

MR. KIM: Two follow-up questions.

The first: In your second

example, of your list of three guarantees that

you went back and reviewed, and maybe I missed

this, but can you specify the coal type that you

anticipated for that system and capacity of

L.A. REPORTING (312) 419-9292

1135

that? I don't have that.

I know the first one you said was

a PRB 800 megawatts, but -- and I think you

identified the second and the third. But do you

have that information from the second example?

MR. DePRIEST: We certainly did, in

the contract, specify the fuels that we are

going to be burning in those units. And it's a

bit of a mixture, in that this particular

utility blends PRB with bituminous coal for

purposes of carrying a load on certain hot

summer days.

And so the guarantees are

structured to accommodate either a full PRB or a

blend of PRB with other higher octane fuels,

like bituminous coals or petroleum, coke,

et cetera.

MR. KIM: Do you recall the capacity

for that system?

MR. DePRIEST: These are --

MR. KIM: Or is this more than one

system?

MR. DePRIEST: These units range in

size from 400 megawatts to 700 megawatts,

L.A. REPORTING (312) 419-9292

1136

approximately 680, I think, something like that.

MR. KIM: The other question that I

had -- and this goes back a little bit, I think,

to something that Mr. Nelson might have been

getting at. Understanding -- and I guess for

now, setting aside the comfort level you might

get with a long-term test versus short-term

test -- isn't it possible that even if you do,

what is, I guess, being referred to now as a

short-term test, that those results might, in

fact, be consistent with what you would see at

the end of a long-term test?

In other words, just because you

don't have a long-term test does not necessarily

mean that the short-term test is not going to be

ultimately correct, as far as what the results

would be in a full scale operation; is that

correct?

MR. DePRIEST: I think you could say

that.

There's a possibility that, at the

end of the first year of operation, that you may

test again and get the same results.

MR. KIM: Sure.

L.A. REPORTING (312) 419-9292

1137

MR. DePRIEST: Certainly that's a

possibility. And, I guess, if you think about

the comfort issue that you mentioned, if I was

asked that question on a who gets the

sulfurization system or electric precipitator or

fabric filter or even an SCR that is relatively

new to the business today, is that how

comfortable are you with the guy who made the

guarantee on day one and also made the guarantee

at day 365? I feel very comfortable that that

guy is going to be able to do it, because we

know the system as well as he does.

In the case of this particular

unit, you know, we're in the learning phase.

And we need, you know, some experience in order

to feel comfortable.

HEARING OFFICER: Dr. Girard.

MR. GIRARD: Can I follow up on that?

Mr. DePriest, in relation to these

guarantees that you actually have knowledge of,

the way I understand it is, once the plant is up

and running and it demonstrates that it meets

the performance targets, then the vendor has

satisfied the guarantee requirements. And then,

L.A. REPORTING (312) 419-9292

1138

long-term, it's the owner's responsibility to

move these targets; is that correct?

MR. DePRIEST: That's correct.

MR. GIRARD: So, typically, how long

do they have to demonstrate this compliance with

the guaranteed limits? Do they, typically, run

for a year, two years, three years, or is it

operational for two weeks or a month?

MR. DePRIEST: It's a bit of a

commercial -- I guess, the question is how you

structure that guarantee. But usually a system

supplier will want to get paid when he's done

meeting his guarantees, maybe some retention,

ten percent of his contract.

And holding that for one year, two

years, three years, costs everybody money. The

equipment supplier as well as the owner, because

the guy jacks up his price to accommodate the

fact that he's not going to get paid for two or

three years after he has supplied the equipment.

So it's a bit of a negotiation.

I'd say, typically, in the past, that guarantee

is performed within the first 90 days of

operation of the unit, demonstrated and then

L.A. REPORTING (312) 419-9292

1139

paid, and the vendor would go away.

It doesn't keep you from

negotiating a contract that says, I want that

guarantee to be tested in the first 90 days, and

I'm not going to pay you your money until a year

later when I test again. So you can structure a

guarantee, you know, any way you want, it's a

matter of how much you want to pay for that

guarantee.

MR. GIRARD: But in terms of these

three contracts you went and looked at last

night in your office that involve guarantees,

are they more in the typical range?

MR. DePRIEST: They are more in the

one time -- first 90 days, test it, if it works,

the vendor gets paid. And the onus is on the to

operator to continue to operate it in the

fashion that it was operated in during those 90

days.

And 90 days is a bit of a guess,

it could be 60 days, depending on the contract.

And 60 days from maybe substantial completion of

erection or 60 days from the first commercial

operation.

L.A. REPORTING (312) 419-9292

1140

There's a number of different

dates that you could use to start the clock

ticking, but it would be fairly short.

MR. GIRARD: Thank you.

MR. RAO: So, typically, whether the

project is a two hundred, $300 million dollars

FGD or a $1 million sorbent technology, it's

still the same way, getting the supply in a 60

to 90-day period where they do the testing and

show compliance?

MR. DePRIEST: That would be,

typically, the case.

In a big scrubber system today, I

think we've kind of moved in the industry over

to a multiple test kind of concept. And what

we're looking at is not necessarily to

demonstrate that the system is capable of

meeting the 98 percent SO2 removal, but we want

to be sure that all the hardware that the guy

supplied, all the pumps and mixers and valves

and instruments are still working a year later.

It's more of a warranty issue more

than a performance issue, in that the quality of

the materials and workmanship supplied, we want

L.A. REPORTING (312) 419-9292

1141

that demonstrated over a longer period of time.

More than -- you know, because of the

significant size of the investment.

MR. RAO: Compliance is just one part

of the --

MR. DePRIEST: Yeah, compliance is

just one part.

MR. RAO: Thank you.

MS. MOORE: Earlier I heard you say

that it might just take one test within those

90 days for them to meet that compliance and

then they're gone?

MR. DePRIEST: Uh-huh.

MS. MOORE: So if they had, you know,

30 runs that they tested day after day and it

wasn't good, then day number 31 they meet their

compliance, now they're gone.

MR. DePRIEST: That's a good point.

We'll establish what tests count.

Where they say, okay, you guys can go in there

and tune your system, tweek it, do whatever

needs to be done to get yourself in a position

where you're comfortable that you will pass the

test and advise us when you're ready to test.

L.A. REPORTING (312) 419-9292

1142

When we test, if it doesn't make it, that test

counts.

But all the tests that he did up

to that point, where he might have been changing

operating conditions or trying to find the right

spot in the run-in, he doesn't have to pass

those, necessarily. We understand that it may

take --

MS. MOORE: He just needs one.

MR. DePRIEST: Right.

MR. GIRARD: Well, let me follow up on

that. In terms of continuous emission

monitoring equipment, where you want to make

sure it works for a long period of time,

typically, how long are the test runs before

they meet their guarantee?

Or is it a warranty situation

where they -- it's warranty'd for a couple of

years or something?

MR. DePRIEST: Well, a typical

performance test may take -- and depending on

the involvement of it, if it's on a -- let's say

we're injecting upstream of an existing

cold-side ESP, we're probably going to want to

L.A. REPORTING (312) 419-9292

1143

have some particulate testing done, some opacity

testing done, as well as the mercury testing

done. So he can demonstrate that he can

simultaneously meet all of those guarantees at

once.

It would just be mercury

reduction. It would be mercury reduction with

no adverse impacts on other things that he'll

have to test.

It might take him four, five days.

Depending on the size of the unit and the

availability of test ports and things like that,

the accessibility and how difficult it might be

to test.

And then, of course, the boiler

has got to be operating right, there's going to

be ups and downs, starts and stops. But once

you get going, a typical test, three, four days.

MR. GIRARD: Thank you.

HEARING OFFICER: Mr. Nelson, thank

you for your patience.

MR. NELSON: I think there may be a

misconception. Do you anticipate, in an

activated carbon ESP guarantee situation, that

L.A. REPORTING (312) 419-9292

1144

the vendor would get ten tries to meet the

guarantee?

MR. DePRIEST: Typically, not.

MR. NELSON: Okay.

MR. DePRIEST: No, we would expect --

we would certainly give the vendor all the time

he needs to come in and manipulate the equipment

that he supplied to find the right spot to run,

so he can meet his guarantees, within reason.

The guy has got to run his power plant.

And he'll give the supplier an

opportunity to make it work. And then when he's

comfortable that it will work, he'll say, okay,

now we are going to run the test.

MR. NELSON: The guarantees that I've

seen -- do the guarantees that you see typically

state very clearly under what conditions the

guarantee is to be met? For example, the load

of the plant, the length of the test, the coal

to be burned. It's usually very specifically

spelled out; is it not?

MR. DePRIEST: That's true.

MR. NELSON: And it's usually at full

load; is it not?

L.A. REPORTING (312) 419-9292

1145

MR. DePRIEST: We would usually

structure a performance test to be able to meet

compliance at the various loads, if we felt that

was important to the particular technology.

Some technology is not so important.

MR. NELSON: With activated carbon

injection, does the resident time of the sorbent

change, when you're a full load or at night,

when you go down to half load, for example. Do

you expect better performance or worse

performance?

MR. DePRIEST: You would expect --

with sorbent injection technology, you would

expect better performances.

MR. NELSON: So in long-term

operations, the plant goes up and down, you

would expect an average of better performance

during a short-term test at full load; is that

correct?

MR. DePRIEST: In aggregate, you

probably would. It's depending on how you look

at, percent reduction or pounds of mercury

captured or how you define better performance.

HEARING OFFICER: Ms. Bassi.

L.A. REPORTING (312) 419-9292

1146

MS. BASSI: I have just one follow-up.

In your second example, where you describe the

five wet FGD limestone-based FGDs and then a

number of activities that a vendor or equipment

supplier would perform if it did not remove

90 percent oxidized mercury, would the company

have to pay a premium, of sorts, to get that

kind of a guarantee?

MR. DePRIEST: Well, certainly, any

guarantee that you get costs money. If you

didn't ask for guarantees, you get a better

price with no risk.

So the more stringent the

guarantees, the more, I guess, restrictive the

remedies that you might put in the guarantee

language as to how you might fix this problem,

and the extent to which you expect him to expose

his contract value to remedies will all affect

the price of the contract and the cost of the

guarantee.

HEARING OFFICER: Mr. Harley first and

then Mr. Nelson.

MR. HARLEY: Is it your testimony that

tuning the system following the installation of

L.A. REPORTING (312) 419-9292

1147

equipment is, typically, a 60 to 90-day process?

MR. DePRIEST: Well, it's very much

dependent on the complexity of what you're

tuning.

MR. HARLEY: What if you were tuning

an ACI upstream on the cold-side ESP?

MR. DePRIEST: Well, I wish I had 30

or 40 of them that I could refer to to know just

how long it might take. But I think it's

something we're still learning.

I don't expect that to be a

particularly difficult tuning operation. But

there are not a whole lot of them running that

we can point to to say it's going to take so

long.

MR. HARLEY: Would it take, in your

opinion, best guess, 60 to 90 days?

MR. DePRIEST: I would certainly think

we would be able to do it in that, yes.

MR. NELSON: And in terms of then

subsequently testing over a range of conditions

or key parameters, you said that testing could

be completed in four to five days?

MR. DePRIEST: Sure.

L.A. REPORTING (312) 419-9292

1148

MR. HARLEY: Are you familiar with the

compliance phase, which is contained in the

proposed rule for coal-fired electric generating

units to meet the requirements of mercury

reduction?

MR. DePRIEST: I believe it's

July '09.

MR. HARLEY: So almost three years?

MR. DePRIEST: Correct.

MR. HARLEY: Thank you.

HEARING OFFICER: Mr. Nelson.

MR. NELSON: With respect to sorbent

injection into ESPs, the guarantees that you

would seek for your clients, I'm going to say, a

certain removal rate at a certain sorbent

consumption or sorbent injection?

MR. DePRIEST: They may, or we may

allow that to flow. We may ask for a guarantee

of such and such reduction and you tell us how

many you need. And we'll evaluate that versus

the other proposals we get.

MR. NELSON: So, in other words, in a

process where the performance is usually

directly proportional to the sorbent consumption

L.A. REPORTING (312) 419-9292

1149

rate, you can always go to increasing the

consumption rate to achieve the removal?

MR. DePRIEST: If you've got a system

that's capable of catching that additional

sorbent that you've injected, yes.

MR. NELSON: Okay.

MR. DePRIEST: That's part of our

evaluation of a guarantee like that, it would be

a function of how much the particular supplier

says he needs to achieve that guarantee.

HEARING OFFICER: Ms. Bassi.

MS. BASSI: Mr. DePriest, what do you

mean by catching that additional sorbent?

MR. DePRIEST: Well, any sorbent you

inject -- if we're talking sorbent injection

technologies, which I guess we are -- needs to

be captured in a particulate control device,

either the bag house or the ESP.

MS. BASSI: Thank you.

HEARING OFFICER: I think we are ready

for Question 15.

MR. DePRIEST: Mr. Chicanowicz has

testified that, "Guarantees in an environmental

control technology provide only partial

L.A. REPORTING (312) 419-9292

1150

compensation for shortcomings and are not

significant factors in the decision to adopt any

particular technology." Do you agree with this

statement?

My answer is, I agree with the

guarantee -- that guarantees may provide only

partial compensation. But I disagree about the

impact of guarantees and their decision to adopt

a particular technology.

A prudent company will not make a

significant investment or rely on a particular

technology to meet regulations for continued

operation without the assurance of a guarantee.

And I guess I'll go on to say that that's just

one component of the evaluation factors that we

use to pick something.

We feel like the guarantees

protect -- really protect the owner from the

investment he's making in that particular

technology. It doesn't protect him from the

ability -- consequential issues of not being

able to operate his power plant.

We can't get the technology

supplier to get behind that particular risk,

L.A. REPORTING (312) 419-9292

1151

that's something the owner never is able to sell

to somebody else. So guarantees are important,

because we want the guy's attention, but they're

not the only thing.

HEARING OFFICER: Question 16.

MR. DePRIEST: No. 16, regarding your

statements beginning on Page 11, Capabilities of

the Existing Electrostatic Precipitator to

Capture Mercury-Specific Sorbents Without

Exceeding the Particulate Emission Limitations

of the Plant, and specifically, "Consequently,

very little, if any, margin typically exists

beyond this design criteria to accommodate the

addition and capture of mercury-specific

sorbents."

Please provide all calculations

and any test results for ESPs in question that

form the basis of your stated opinion,

including, A, any CFD flow modeling of the ESPs,

B, Calculations of sorbent injection rates fly

ash mass flow rates and capture rates of sorbent

and fly ash in the ESPs. Please be prepared to

go through these calculations in detail for at

least one example, and C, Any test results of

L.A. REPORTING (312) 419-9292

1152

sorbent injection tests performed on the

specific Illinois power plant ESPs in question.

And the answer, please refer to my

answers to Questions 6 and 14. I could reread

them, if necessary.

And then I go on to say, we are

not aware of any specific tests done on Illinois

units. So this is a specific test done upstream

of existing ESPs.

However, based on our extensive

experience working with these units, these

specific units in the state of Illinois and

others of their vintage, and in some cases as

the original equipment designer, we understand

that many of the units have little precipitator

margin.

HEARING OFFICER: I have a question

when you say "we understand." Is that based on

information from the companies or based on your

own expertise?

MR. DePRIEST: It's based on our own

qualitative analysis that we did looking at

many, if not probably 90 percent, of them. I'd

have to look at the numbers.

L.A. REPORTING (312) 419-9292

1153

We were actually the original

design engineer on the ESPs in question.

HEARING OFFICER: Thank you.

Mr. Bonebrake.

MR. BONEBRAKE: And, Mr. DePriest,

just for clarification, your statement, I think

this is consistent with what you said in

response to Question No. 6, that cited in

Question No. 16, your particular statement is

based upon the qualitative analysis that you

referenced earlier rather than the particular

calculations; is that correct?

MR. DePRIEST: That's correct. The

conclusions that we've drawn are not based on

calculations that we've performed, but based

more on the qualitative assessment of the

arrangement of the equipment at the site, the

size of the precipitators, the current emission

limits and opacity levels, and then looking at

what would happen qualitatively if you put a

bunch of sorbent into that same particular

controlled device and asked it to perform at

that same level.

So our analysis is not based on

L.A. REPORTING (312) 419-9292

1154

calculations but based on more of a qualitative

nature and our knowledge of the equipment in

question.

HEARING OFFICER: Would it be safe to

say, Mr. DePriest, and please forgive me if I'm

mischaracterizing this, but I'm trying to get

this in the simplest of terms. A lot of your

testimony, where we're asking for specific

details about how you did this, basically was

put together by you and/or your company looking

at your clients, your contracts and what you've

done in the past and then taking that

information and looking at the requirements of

the rule and saying, generally, or -- and you

keep saying qualitative analysis, but...

MR. DePRIEST: Right.

HEARING OFFICER: You did not

specifically sit down with -- and let's make up,

XYZ company who has been your client for 45

years and you've built their facilities and say,

okay, if XYZ has to meet this 90 percent

reduction, this is exactly what they would have

to do?

MR. DePRIEST: I think this question

L.A. REPORTING (312) 419-9292

1155

might come up later but, I guess, to answer your

question now, the way we assisted the clients in

question here is, they asked us to look at --

specifically look at each and every one of their

coal-fired units in their system. And we

identify -- we did do that.

We sent a team of engineers to

every site. And with that team of engineers,

they went to the site and they looked at if we

installed an activated carbon injection system

upstream of the existing ESP, what would that

cost and what would it look like? If we had to

install a fabric filter on that site, what would

that look like, ductwork arrangements,

accommodations for draft system modifications,

ox power system modifications arrangement at the

site, and the cost to do all that.

What would it look like to add a

wet FGD system to each one of these sites. We,

essentially, established a database of cost,

both capital and O&M, to the application of

different technologies at each of these stations

and we also made a judgment as to how they would

perform from a mercury standpoint.

L.A. REPORTING (312) 419-9292

1156

And we told all that to our

client -- the clients, and they took that

information and internally made a -- came up

with a strategy on how they might achieve either

the CAMR requirements, the CAIR requirements or

now the Illinois mercury requirements. And how

those might fit together if they were happening

at different times, so sequentially.

So we, essentially, provided them

with all the data that they needed to make an

analysis. We didn't do the analysis for them.

I think that's part of the reason

why I made that statement at the beginning is

that we -- their strategic plan was, for the

most part, performed and developed by them, they

sent information we gave them.

MR. GIRARD: Mr. LePriest, in relation

to the existing ESPs that you must have thought

about in coming up with the answer to this, I

mean, what is a typical margin that exists

beyond the design criteria? I mean, what's the

ballpark margin that you're sort of keeping your

head as an engineer?

MR. DePRIEST: That's a very good

L.A. REPORTING (312) 419-9292

1157

question. I think, if you'd look at these

(indicating), and it's a bit complicated in this

situation, because these units in the state of

Illinois, for the most part, maybe even in all

cases, were designed to burn high sulphur

Illinois basin coals -- high, meaning sulphur.

Most of them have been converted,

and they were designed with certain margin

deflect particulate based on that fuel. They've

since been changed to, for the most part, to PRB

coals, much lower sulphur, much more difficult

to collect ash.

Any margin that we might have had

in there, in most cases, was consumed, to the

point where the utility had it go in and

actually artificially add SO3 or some other

conditioning agent to the flue gas in order to

meet the performance that they're required to me

by permit.

So we design then with a certain

margin, initially, on high sulphur coal, they

were switched to low sulphur coal, the margin

went out the window. They came back with an ash

conditioning system to try to cover that margin,

L.A. REPORTING (312) 419-9292

1158

and successfully, I would say.

There are some plants, better than

others, with more margin in it than others. But

all now are operating within their permit

levels.

And I haven't answered your

question about the actual degree or percent of

margin. I guess, with the current -- I'm trying

to think of which way to look at this.

I guess from an opacity

standpoint, you think of the Ameren units in the

state of Illinois, they have to meet a

30-percent opacity limit on their stations.

They operate up to the neighborhood of 25.

So if that's any indication of

margin, even though you have to know the slope

of the curve as you increase particulate

loading, how that affects opacity, and that's a

complicated curve, depending on the people with

the ash that you're actually looking at with

your opacity meter. But we think that's pretty

darn close, it's kind of getting marginal.

You have a 25 percent opacity and

you've got a 30 percent limit. And you're

L.A. REPORTING (312) 419-9292

1159

talking about adding more particulates on the

front end of that precipitator.

So we made a judgment as to how

much we felt the guy could get with mercury

control, and it wasn't 90 percent, in our

opinion, on those units.

MS. BASSI: How about particulate

matter removal?

MR. DePRIEST: The particulate matter

removal is, I guess, another story. Most of

these plants also have a particulate emission --

an actual mass in emission rate limitation that

they have to meet.

And that is different on every

station. I currently don't have that

information in front of me to know what that

would be.

But we do recognize that any

addition of particulate, at least in our

opinion, has the very real possibility of

increasing the outlet loading. The degree of

margin that they have between their permit limit

and their actual operation, I'd have to go back

and look at the data, I don't recollect that

L.A. REPORTING (312) 419-9292

1160

right now.

HEARING OFFICER: Mr. Kim first and

then --

MR. KIM: Yes. Going back -- and just

to clarify, I think I know the answer.

But when you made reference to a

group of your company's people going out and

doing a plant by plant analysis of their

specifics and configurations and so forth, the

result of that information that was prepared --

and, you know, I think you said you prepared the

data -- you didn't, necessarily, do the

analysis, but you prepared the data so that the

companies themselves could do the analysis. I

don't want to put words in your mouth, but

that's what I got from --

MR. DePRIEST: Yes. Just to clarify

it further, to be totally honest here, we did

that type of analysis for two of the utilities

in question. The third utility, we actually

assisted them in finding a strategy.

MR. KIM: Well, okay. My first

question was, is that information included

within the umbrella of information that you had

L.A. REPORTING (312) 419-9292

1161

identified earlier on in the hearing as being

proprietary and therefore not something you were

able to share with the Pollution Control Board?

MR. DePRIEST: That's correct. Even

though -- since yesterday's discussion, I

remembered that my testimony actually does

include three examples of three different

proprietaries in the state of Illinois, where

the utility told us that we could go ahead and

share the information on costs with the Board.

And I've included that in my

testimony, three specific examples on all that

we've done, that they felt were, apparently,

okay to talk about.

MR. KIM: And when you said that there

were two utilities that you prepared that type

of analysis for and the third that you assisted

them, can you identify which two you did the

analysis work for and the third that you

assisted in the analysis?

MR. BONEBRAKE: And I think you're

mischaracterizing --

MR. KIM: And if I am, I apologize.

MR. BONEBRAKE: Because -- to clarify.

L.A. REPORTING (312) 419-9292

1162

I think you're suggesting that Sargent & Lundy

did two CAMR assessments for a couple of

companies. And I don't think that's what he

said, Mr. Kim, so maybe you can clarify.

MR. KIM: Yeah, please do. If I

misstated that, I apologize.

MR. DePRIEST: If he said that, we

didn't do that.

MR. KIM: Okay.

MR. DePRIEST: We developed the data

and capital and O&M costs and performance

expectations for all the units in the system for

the application of a number of different

technologies. And then we gave that to the

owner and he took that information and developed

his own strategy.

MR. KIM: Okay.

MR. DePRIEST: We did not develop --

two cases, we did not develop the strategy. The

third case, we actually did that part, as well

as helped them develop the strategy.

MR. KIM: And I guess that's what I

was getting at. Can you identify, when you say

them and those two --

L.A. REPORTING (312) 419-9292

1163

MR. DePRIEST: Ameren is the one that

we helped. Midwest Gen and Dominion, we simply

gave the information.

MR. KIM: Okay. And then I understand

that you feel constrained, because of your

contract, from a proprietary standpoint, that

you cannot provide the information that we

received in our questions.

Do you know -- and you, to the

extent or the best of your knowledge -- do you

know if your clients' utilities would have the

same response if the question were put to them

in terms of them being able to provide the Board

with that information? I understand that you're

not an employee of one of the utilities.

MR. DePRIEST: I don't want to put any

words in their mouth, but I think Ameren has

kind of told everybody what they're thinking

about doing.

MR. KIM: Do you know if -- well, and

Ameren has sort of put themselves into a sort of

a special box in these proceedings. The other

clients that you work with, do you have any kind

of understanding as to their position on this?

L.A. REPORTING (312) 419-9292

1164

MR. DePRIEST: I can only tell you

what I think is public. I mean, Dynegy

certainly has made it public, what they intend

to do at a number of their stations. That's

probably the extinct of what I know.

MR. KIM: Sure. My last question is,

did you have an opportunity in the course of

preparing your testimony to review any of the

documents contained in the Illinois EPA's

Technical Support Document, or TSD, that was

submitted in conjunction with the rule of the

Board?

MR. DePRIEST: You know, I glanced at

it. I -- I didn't really -- I was looking for

this TTBS thing, I didn't find it, so...

MR. KIM: Well, specifically, there's

a table in the TSD, Table 8.9, and it's

captioned as or identified as Example Technology

Section, Selection and Cost For Illinois Mercury

Rule Compliance. And that was an attempt by Dr.

Staudt on behalf of the Illinois EPA to do a

plant by plant and unit by unit breakdown of

estimated technologies and costs and so forth.

Have you seen that table, by any

L.A. REPORTING (312) 419-9292

1165

chance?

MR. DePRIEST: You know, I did glance

at that. In fact, I made reference to one

numbered in here, because one of the examples

that we have used in here was the same -- one of

the same stations that Dr. Staudt looked at.

MR. KIM: In the course of your site

by site or unit by unit analysis that you did

for your client, did you perform a similar type

of breakdown or estimate?

MR. DePRIEST: You have to tell me

what's on that table, I can't remember.

MR. KIM: I can show it to you.

MR. DePRIEST: Okay. And just for

clarification, this is Table 8.96 TSP.

MR. KIM: Correct.

MR. DePRIEST: Yeah, it looks

consistent with the information we also

developed.

MR. KIM: Okay. Thank you.

HEARING OFFICER: Mr. Nelson first and

then Mr. Harley. Mr. Nelson --

First you, Mr. Harley.

MR. HARLEY: In your testimony when

L.A. REPORTING (312) 419-9292

1166

you were talking about going out and doing this

assessment work for your utility clients, you

talked about determining what they would need to

do for CAMR, for CAIR and determining what they

would need to do for the Illinois Mercury Rule.

Did you specifically parse out

what would be required for compliance with each

of those programs, or was it not in compliance

with the full speed of near term regulatory

requirements?

MR. BONEBRAKE: And again, objection.

I think Mr. Harley is mischaracterizing the

prior testimony.

But go ahead, Mr. DePriest.

MR. DePRIEST: Well, maybe if they

tell you the dates that we did this work will

help identify whether or not we were looking at

CAIR, CAMR or the Illinois Rule. The Ameren

work, we did that in 2003, 2004; Midwest Gen

work we did in 2005; Dynegy work in 2004, 2005.

So you can probably look and see

that the Ameren work was done prior to the

Illinois Rule being proposed. So that part of

it they did, based on information we gave them,

L.A. REPORTING (312) 419-9292

1167

back in 2003, 2004.

They used that then as -- and

probably modified it, as necessary, to represent

the current day costs, and use that as part of

their Illinois Rule evaluation.

MR. HARLEY: The work that you did for

Ameren in 2003, 2004, was it mercury only or was

it also looking at issues related to compliance

with near term SO2 and NOx productions, as well?

MR. DePRIEST: It also looked at NOx,

SO2 and mercury.

MR. HARLEY: So is it fair to say that

the alternatives that you identified for these

companies were alternatives and costs that would

be associated both with mercury compliance and

also with compliance with NOx and SO2 limits?

MR. BONEBRAKE: And just for

clarification, is that question beyond Ameren?

Is that all the companies that Mr. DePriest has

mentioned?

MR. HARLEY: Why don't we start with

Ameren.

MR. DePRIEST: Is that the same

question you just asked me a minute ago? I

L.A. REPORTING (312) 419-9292

1168

think the answer is yes. We looked at all three

companies.

MR. HARLEY: And the cost for Midwest

Generation, it would have been the costs and

alternatives that would be required, not only

for mercury compliance, but also for

requirements related to NOx and S02 reduction?

HEARING OFFICER: And just for the

record, NOx is N-O-sub X, S-O-sub 2.

MR. DePRIEST: That's correct.

MR. HARLEY: And the third company was

Dynegy?

MR. DePRIEST: That's correct.

MR. HARLEY: The same is true for the

assessment you did for Dynegy?

MR. DePRIEST: I'm thinking, Dynegy.

I would say -- I believe that's

true. I'd like to go back and look at the

report to be sure that we covered, you know,

every one at every unit.

I'm not positive, but I'm pretty

sure we did.

MR. HARLEY: Is it fair to say that

the alternatives that you recommended for these

L.A. REPORTING (312) 419-9292

1169

companies would be designed to control not only

mercury but also have the additional benefit of

controlling other things, as well, like NOx and

SO2?

MR. BONEBRAKE: And again, I think

you're mischaracterizing the testimony regarding

the recommendations of the multiple companies.

But you can proceed. Go ahead and

answer.

MR. DePRIEST: We gave them enough

information for them to be able to independently

evaluate the client strategies for each

individual pollutant, as well as developing

strategies that were comprehensive in nature to

be able to find a solution for all, two, three.

So the information was robust enough for them to

be able to, let's say, develop an independent

mercury control.

MR. HARLEY: Thank you.

HEARING OFFICER: Mr. Nelson.

MR. NELSON: First, I'd like to thank

you for putting yourself under a microscope

today.

If these reviews in your cost

L.A. REPORTING (312) 419-9292

1170

calculations were calculated in 2003, 2004 and

even 2005, how many demonstrations -- how much

data did you see on brominated carbon injection

into ESPs for subbituminous coals?

MR. DePRIEST: Well, it's difficult to

answer. If you go back to 2003, it was pretty

slim pickings.

In 2004, I think we had some data.

In 2005, we had some data.

MR. NELSON: Was it --

MR. DePRIEST: I think Holcomb was

2004; wasn't it?

MR. NELSON: And then it took awhile

for the results to be public; right?

MR. DePRIEST: Yes. Even though we

had -- we had some access to them.

MR. NELSON: Now, Holcomb deals with a

fabric filter in a spray dryer; does it not?

MR. DePRIEST: Yes, it does.

MR. NELSON: And those aren't the kind

of plants that your clients have; are they?

MR. DePRIEST: No. But they could

have, depending on their --

MR. NELSON: They could.

L.A. REPORTING (312) 419-9292

1171

MR. DePRIEST: -- strategy for other

pollutants.

MR. NELSON: But with respect to

performance data, on brominated carbon and

subbituminous coal and simply cold-side ESPs,

which is the nature, by far, of the

configuration in Illinois, you had no data then

to reach your conclusions; is that correct?

MR. DePRIEST: Well, we, I guess,

didn't really reach any conclusions. We

provided information as to what it would cost to

deploy these technologies.

And I think, even though I gave

you static days and times, we continued to

advise and consult our client on the work that

we did. And we continued to update that

information as they feel is appropriate.

So we did the base study on those

years, but we have continued to work with them,

even to today, on how that data might change.

MR. NELSON: Well, let me ask you

specifically, have you yourself reviewed the

detailed month-long trial results of ADA-ES with

brominated carbon Ameren's Merrimac Station?

L.A. REPORTING (312) 419-9292

1172

MR. DePRIEST: Yes, we have looked at

that.

MR. NELSON: Were you aware that they

averaged out 93 percent mercury removal for the

month at an injection rate of a little over

three times for ACF?

MR. DePRIEST: We're aware of the data

to that respect, yes.

MR. NELSON: Are you aware of any

deleterious ESP effects or passing increases

that they reported?

MR. DePRIEST: We understand that the

data looks very encouraging. It's also

important to know that it's a very large ESP,

very long inlet ductwork, no SO3 conditioning.

MR. NELSON: Have you reviewed the

detailed month-long trial results of the ADA-ES

with brominated carbon at the Laramie River

Station?

MR. DePRIEST: No, I have not.

MR. NELSON: Which has an ESP of --

MR. BONEBRAKE: Is that a question?

MR. NELSON: I'm not finished with the

question.

L.A. REPORTING (312) 419-9292

1173

So you weren't aware that they

averaged over 90 percent renewable injection

rates?

MS. BASSI: He's answered that

question. He's said he's not familiar with it.

MR. NELSON: Have you reviewed any of

the results from ALSTOM's month-long trial at

Pacific Corp's, Dave Johnston Station of

brominated carbon?

MR. DePRIEST: No, I've not.

MR. NELSON: You're not aware of that

one either?

MR. DePRIEST: No.

MR. NELSON: Have you reviewed the

detailed trial results of the Sorbent

Technologies month-long trial at the Detroit's

Edison St. Clair Station, brominated carbon,

subbituminous coal and --

MR. DePRIEST: Yes. Let me clarify.

I hate to -- I'm kind of answering

for myself, I've got a staff of a lot of other

technical experts who do review this

information.

I'm certainly aware of the

L.A. REPORTING (312) 419-9292

1174

testimony that was done at Laramie River, Dave

Johnston and the Detroit Edison project, yes.

MR. NELSON: Are they here today to

testify?

MR. DePRIEST: No, they aren't. I'm

kind of testifying as the representative group

that did the work.

MR. NELSON: But you yourself are not

aware of any of these detailed results?

MR. BONEBRAKE: Objection. He's

already answered that question.

MR. DePRIEST: I mean, not enough to

be able to answer the questions.

MR. NELSON: Are you aware of the

trial results of the URS Corporation's

demonstration last year with brominated carbon

injection at Great River Energy Stanton Station

Unit 1 with cold-side injection, subbituminous

coal and brominated carbon?

MR. DePRIEST: Not specifically, no.

Not these specific data, no.

But that type of information was

used to help us draw the conclusions at the

river, if that's where you're going.

L.A. REPORTING (312) 419-9292

1175

MR. NELSON: If those results -- and

most of these results were just released within

the last year, or in some cases six months, how

could they have informed your recommendations

and your cost calculations done in 2003, 2004,

and 2005?

MR. DePRIEST: As I mentioned, we've

been continuing to work with our clients

updating the information that we originally

developed in those years that we started that

work, to assist them in them creating their own

strategic plans. So as the industries moved,

we've helped our client move with that

information.

And granted, you know, you mention

all these tests, and I would be the first one to

admit that a lot of this stuff looks very

encouraging. But it's also very short term,

there's also a lot of things that we don't

understand about why it happened to perform the

way it did, either good or bad.

And some of those things make us

feel uncomfortable about predicting that we'd be

able to achieve these same results on the units

L.A. REPORTING (312) 419-9292

1176

that we're applying to. Many of those units, as

you mentioned, do not use SO3 injection for

particulate control, their particulate control

devices were designed to operate on low sulphur

coals, which is now what we're operating the

Illinois units on.

The Illinois units were not

designed for the sulphur coals. Those units

that we mentioned, Dave Johnston, Laramie River,

I remember the Stanton Station.

MR. NELSON: Do any Midwest Generation

plants do SO3 injection?

MR. DePRIEST: I believe not.

MR. NELSON: Do any Dynegy plants?

MR. DePRIEST: I believe they do.

MR. NELSON: Which ones?

MR. DePRIEST: I don't know, because

we just -- I think we just switched Wood River

over to low sulphur coal with --

MR. NELSON: Are you aware --

HEARING OFFICER: Let him finish,

Mr. Nelson.

MR. DePRIEST: -- with SO3 injection,

I believe. I'd have to --

L.A. REPORTING (312) 419-9292

1177

MR. NELSON: Are there alternative

testing for injection for fuel gas conditioning?

MR. DePRIEST: I understand there are,

yes.

MR. NELSON: Are you aware of any of

the DOE trials where brominated carbon was

simply injected upstream of an ESP at a plant

that runs primarily subbituminous coal was not

able to achieve at least a 90 percent mercury

removal?

MR. DePRIEST: I'm not aware of any.

MR. NELSON: Are you aware of any DOE

trials where subbituminous coal, ESPs and

brominated carbon injection that observed

opacity increases over ESP problems?

MR. DePRIEST: I'm not aware of any.

MR. NELSON: Are you aware of the ESP

and particulate emission results -- wait, just

let me take a step back.

Were you aware of DOE trials that

indicate improved opacity performance with

brominated carbon injection, for example,

Progress Energy's Lease Station?

MR. DePRIEST: I have heard some

L.A. REPORTING (312) 419-9292

1178

things about that. I am a bit baffled by it,

but yes, I've heard that.

MR. NELSON: Are you aware of the ESP

and particulate emission results at Stanton 1,

which burned subbituminous coal because of

cold-side ESP?

MR. DePRIEST: Not the specifics, no.

I understand that they didn't have any trouble

with their particulate loading. But I don't

know the actual specifics.

MR. NELSON: Are you aware that in the

particulate emission measurements that

particulate emissions went down with the

brominated carbon injection relative to the

baseline period at Stanton 1?

MR. DePRIEST: I heard that. Have

those results been repeated?

MR. NELSON: Yes. Would you like to

see them?

I'd like to enter this into

evidence, if I may.

MR. DePRIEST: It sounds like we may

have a new emerging technology.

HEARING OFFICER: That first document

L.A. REPORTING (312) 419-9292

1179

that I've been handed is Great River Energy

Stanton Station Unit 1. We will mark this as

Exhibit 116 if there is no objection.

MR. NELSON: And the second document?

HEARING OFFICER: I haven't admitted

the first document yet.

Is there any objection to the

admission of the first document?

MR. BONEBRAKE: The first document

being?

HEARING OFFICER: Great Rivers Energy

Stanton Station Unit 1.

MR. BONEBRAKE: I will reserve my

objection until we find out a little bit more

information regarding this document, Madam

Hearing Officer.

HEARING OFFICER: All right. For

purposes of the record, we're going to mark this

as Exhibit 116.

(WHEREUPON, a certain document was

marked Exhibit No. 116 for

identification, as of 8/18/06.)

HEARING OFFICER: And give me one

second for the second document.

L.A. REPORTING (312) 419-9292

1180

The second document is a Mercury

Control Field Testing at Stanton Station Unit 1,

draft site report prepared by Lynn Brickett,

dated April 2006. If there's no objection, we

will mark this as Exhibit 117.

Seeing this as Exhibit 117.

(WHEREUPON, a certain document was

marked Exhibit No. 117 for

identification, as of 8/18/06.)

MR. NELSON: I'll call your attention

to the short document. Both of these are in the

longer document, I just took out two graphs from

the longer document.

HEARING OFFICER: So these are a part

of the Lynn Birkett report?

MR. NELSON: Exactly. Just larger.

MR. BONEBRAKE: I'm sorry, I have two

documents in front of me, one of which has been

marked Exhibit 116 and is a longer report. It's

your representation, Mr. Nelson, that 116 is an

extract from the larger report?

MR. NELSON: Exactly.

MR. BONEBRAKE: And for clarification,

can you tell us what page this is an extract

L.A. REPORTING (312) 419-9292

1181

from? That is -- 116 is extracted from what

pages of the report?

MR. NELSON: Pages 39 and 54.

MR. BONEBRAKE: And the larger report,

Mr. Nelson, is black and white, what has been

reported to be an extract is in color. Is it

your representation that the color is from the

original version?

MR. NELSON: Yes, they are. And I

will give a PDF version so that you can get the

whole thing in color.

If we look at the first page,

please, does this look like the month-long, or

actually longer than a month, from 9/15/05 to

10/27/05, where later mercury continuous

emission monitor plots of inlets -- or excuse me

mercury removal versus time?

MR. BONEBRAKE: And for clarification,

Mr. Nelson, you're asking that question based

solely upon his review of this particular page?

MR. NELSON: Just today, right. Just

today.

MR. DePRIEST: What was the question?

It looks like a month's worth of data, yes, or a

L.A. REPORTING (312) 419-9292

1182

little more.

MR. NELSON: I call your attention to

the top right-hand corner. Does it look like

the injection rates in orange from below two and

a half to a little over three pounds per million

ACF on the right axis at the subbituminous coal

plant with a cold-side ESP, they were able to

achieve over 90 percent mercury removal?

MR. DePRIEST: Yes.

MR. NELSON: Are you familiar with the

URS Corporation?

MR. DePRIEST: URS?

MR. NELSON: USR that performed this

trial?

MR. DePRIEST: Yes.

MR. NELSON: Do you have a -- would

you like to express an opinion as to their

competence?

MR. DePRIEST: I have no reason to

believe they are not competent.

MR. NELSON: Are they a sorbent

supplier?

MR. DePRIEST: Not that I'm aware.

MR. NELSON: Are you aware that they

L.A. REPORTING (312) 419-9292

1183

supply activated carbon injection equipment?

MR. DePRIEST: I understood that they

were thinking about doing that. Are they a

supplier of that now?

MR. NELSON: I'm not aware of that.

So it looks like this plant is

another plant that they got 90 percent at very

low injection rates.

MR. DePRIEST: Right.

MR. NELSON: The injection rates

that --

MR. BONEBRAKE: Is that a question,

Mr. Nelson?

MR. NELSON: The injection rates

they're talking about, two to three and half

pounds per million cubic feet of gas, what does

that translate to in additional mass loading to

the ESP?

MR. BONEBRAKE: For clarification, are

you talking about this particular plant or just

generally?

MR. NELSON: Any plant. It would be

the same.

If you add about two pounds to

L.A. REPORTING (312) 419-9292

1184

three pounds per million cubic feet of gas to a

subbituminous coal plant ESP, approximately how

much in percentage terms would you be increasing

the loading to that ESP?

MR. DePRIEST: Well, that sounds like

a calculation to me, I can't do it in my head.

Certainly, it's a function of the ash loading

without that, and which is a function of the

fuel you were burning, lignite, BRB, bituminous

all different ash levels.

MR. NELSON: Would you be surprised if

it was a one to two percent increase in loading

to ESP?

MR. DePRIEST: It wouldn't be a

surprise, no.

HEARING OFFICER: I'm sorry, I didn't

hear that answer.

MR. DePRIEST: It wouldn't surprise

me, I guess. But, you know, it depends on the

ash loading.

MR. NELSON: The ash systems that your

company designs or specifies, ash handling

systems, how much variability day-to-day or coal

do you -- in percentage terms, what is their

L.A. REPORTING (312) 419-9292

1185

turn-down ratio or turn-up ratio, typically?

MR. DePRIEST: For the ash --

MR. NELSON: For the ash.

MR. DePRIEST: -- Removal system?

MR. NELSON: Uh-huh.

MR. DePRIEST: The ash removal system

is operated on an intermittent basis, as you

fill the hoppers below with the ESP or the

fabric filter.

MR. NELSON: Okay.

MR. DePRIEST: So it's not a

continuously operating system, it operates when

detected that the levels in the hoppers require

that.

MR. NELSON: The ash loading to a

typical ESP varies on a weekly basis or daily

basis by what kind of fraction, five to ten

percent, plus or minus 20 percent?

MR. DePRIEST: Whatever the variation

in the fuel ash level is. If you're getting at

will the addition of activated carbon, somehow

or another, impact the ash handling system, I

don't expect it would.

There's enough margin to handle

L.A. REPORTING (312) 419-9292

1186

it.

MR. NELSON: More precisely, the ESP

operation -- does the loading to the ESP

typically vary, plus or minus ten or 20 percent,

on a daily or a weekly basis?

MR. DePRIEST: If you're dealing with

lignite, it's going to vary even more than that.

If you're dealing with a bituminous coal,

probably not that much.

MR. NELSON: What about a

subbituminous coal?

MR. DePRIEST: Subbituminous coal, I

wouldn't -- you know, because it's a fairly low

ash, it doesn't take much to change it from a

percentage standpoint. So it might be a

fairly --

MR. NELSON: Like high, like ten or 20

percent?

MR. DePRIEST: I hesitate to give you

numbers without looking at data, but...

MR. NELSON: Thank you.

Let's turn to the second page.

I'll give you a minute to look at this.

I've added the pink circles, they

L.A. REPORTING (312) 419-9292

1187

aren't in the original.

HEARING OFFICER: I'm sorry, you've

added what?

MR. NELSON: The pink circles.

They're not in the original URS or DOE

documents.

Could you read the line with the

second circle that describes the range of the

red dotted line.

MR. DePRIEST: It says range of single

point baseline measurements from July

parametric.

MR. NELSON: And they vary between

about what emission concentrations with baseline

conditions?

MR. BONEBRAKE: Madam Hearing Officer,

we're getting into an issue, as we did

yesterday, where Mr. Nelson is simply asking a

series of questions of the witness, which

essentially are nothing more than the witness

reading something from documents, that which

you've seen before, into the record. The

documents speak for themselves. This particular

document has been marked as an exhibit.

L.A. REPORTING (312) 419-9292

1188

If there's something that needs to

be drawn by the Board from the document, it's

part of the record.

HEARING OFFICER: I believe we're

going to give him a little leeway, because I

suspect that, as he was with the first document,

he is establishing Mr. DePriest's familiarity so

that he can then ask him questions about

concluding.

Is that correct? You aren't just

reading the document?

MR. NELSON: No, Mr. DePriest has

testified. The whole basis of his testimony on

costs has to do with required increases of

particulate emission requirement, ESPs, that had

to be larger fabric filters that have to be

built to increase particulate emissions.

And I'm trying to establish the

level of his experience in looking from these

activated carbon injection and the actual data

on effects on whether particulates increased or

not.

MR. BONEBRAKE: It mischaracterizes

his testimony, but the record will say what it

L.A. REPORTING (312) 419-9292

1189

says.

MR. GIRARD: Let me ask a question.

Mr. Nelson, the figure 5-10 on

Page 39 of Exhibit 117 is before us. What do

you think that figure shows?

MR. NELSON: In summary, I think that

it shows that over the course of this 30 or

34-day test, that the particulate emissions with

the brominated activated carbon injection at

this plant actually do not show increased

particulate emissions, but actually show

equivalent or decreased particulate emissions.

That these blue bars (indicating) are not above

the top red line of the baseline measurements

without activated carbon injection.

But particulate measurements are

actually within the standard band, or with time,

go down with brominated carbon injection.

That's all.

MR. GIRARD: Thank you.

Mr. DePriest, is there anything in

Mr. Nelson's explanation that makes you want to

change anything in your testimony?

MR. DePRIEST: I don't think so. If I

L.A. REPORTING (312) 419-9292

1190

could comment on this though, maybe I would --

HEARING OFFICER: Please do.

MR. GIRARD: Yeah. What comments do

you have?

MR. DePRIEST: Well, I'd like to know

how this system operated just normal variation

of the particulate loading that you would

normally see on a unit like this, operating

without any activated brominated or otherwise

carbon in it. Is this a -- the blue line here

(indicating), is that representative of normal

background emission limit fluctuation at the

Stanton Station? I mean, these don't look

particularly -- the variation isn't a surprise

to me, even without activated carbon injection.

So I'm wondering whether or not

that unit would run like this, activated outlet

loading with or without brominate. I'd like to

know that.

MR. GIRARD: Well, Mr. DePriest,

Exhibit 117 is an 81-page draft, professionally

papered. Do you think you would need more time

to read this paper to answer the questions you

have posed?

L.A. REPORTING (312) 419-9292

1191

MR. DePRIEST: I'd -- that would be

welcome, if I could.

MR. GIRARD: Did you think there's a

good chance that the questions that you have

would be answered in the paper?

MR. DePRIEST: They will either be

answered or I'll have questions about the data

in the paper as to how it's -- whether or not

they scientifically really looked at the effect

that the addition of activated carbon had on the

performance of that precipitator in question.

Certainly, you'd want to establish -- get a good

background for how it runs, day in and day out,

particulate loading, maybe even similar to this

without activated carbon, such as, they added

activated carbon and nothing changed, is a good

possibility.

I'd like to get into that type of

an analysis with the authors of this paper,

whether they looked at that.

MR. NELSON: Okay.

MR. DePRIEST: And, I guess, I'm a

little concerned about the range of single point

baseline measurements as to what that means,

L.A. REPORTING (312) 419-9292

1192

single point.

MR. NELSON: Well, they are baseline

measurements. The red is what it is without

injections.

MR. BONEBRAKE: Well --

MR. DePRIEST: It's a single point.

And we all know, although when it comes to

sampling for particulate in a fuel gas stream,

single point is meaningless.

MR. NELSON: In a traverse, how many

points are typically standard?

MR. DePRIEST: The EPA has rules and

guidelines as to how to traverse a duct. And

it's a function of, you know, how many duct

diameters downstream from the disturbance in the

flue gas path.

I'd say, typically, you're going

to be sampling, somewhere in the neighborhood of

48 points when you do a traverse. At least if

you follow the EPA guidelines.

I know, I see you shaking your

head. But if you look at Method 1, EPA

Method 1, it's going to tell you.

Most power plants doing the

L.A. REPORTING (312) 419-9292

1193

ductwork configurations is going to require a

fairly robust number of sampling points to

achieve the requirements of Method 1 IEPA

federal register guidelines.

MR. NELSON: Last question.

If the particulate measurements

showed particulate emissions greater than the

baseline period, would you think that that would

be evidence of an increased particulate

emissions with sorbent injection?

MR. DePRIEST: I guess I'd have the

same comment. I'd like to be able to be sure

you understood the background baseline

particulate emissions from the station without

carbon injection, long term as compared to, you

know, whatever you mentioned here about a

particular day, 10/20/2005, when you happen to

be injecting between three and three and a half

pounds and doing better than 90.

It's very encouraging information,

and I'd like to dig into it.

MR. NELSON: Thank you.

MR. BONEBRAKE: Just one follow-up

question.

L.A. REPORTING (312) 419-9292

1194

HEARING OFFICER: Sure.

MR. BONEBRAKE: Mr. DePriest,

Dr. Girard asked you a question about whether it

would be helpful or assist you to have more time

to view the report dated April 2006, and you

answered that question. And my follow-up is, as

Dr. Girard pointed out, that report is entitled

Draft.

Would it also assist you in

forming any special opinions, based upon which

document to review, the final version rather

than a drafted version of the report?

MR. DePRIEST: Oh, certainly if

there's a final.

MR. BONEBRAKE: Thank you.

HEARING OFFICER: Okay. I have to ask

this follow-up then.

I understand that this is a draft

paper, but would you expect to see substantial

changes between a draft that circulated publicly

and a final draft on a report of this type, when

it comes to the data?

MR. DePRIEST: Well --

HEARING OFFICER: Is the data going to

L.A. REPORTING (312) 419-9292

1195

change between the draft and the final?

MR. DePRIEST: My only concern is the

scientists that did this work would -- and I

assume they're looking at the data and looking

for inconsistencies or unexplainable occurrences

in the data that might result in them actually

pulling some of the data their report based on

such an analysis. Whether or not that's been

done, is part of them developing a draft.

I'm not sure, but I wouldn't -- to

answer your question, I'd be surprised to see

that happen, but it wouldn't be totally out of

the question.

HEARING OFFICER: Okay. Thank you.

MR. GIRARD: Mr. Nelson, do you know

if this paper has been through the DEO or EPA or

whoever has commissioned it, their review

process? I mean, there are drafts and there are

drafts, has this been peer reviewed in any way?

MR. NELSON: I was told by DOE that

this will probably not be published in its final

form as an individual site report. It's part of

a larger contract that involves like three

different plants, that's typically the way they

L.A. REPORTING (312) 419-9292

1196

do it.

And then it will appear in a final

report that will include all three plants. So

this will be like one chapter in a three chapter

final report.

And that won't be done until they

finish the last plant, which is -- you know, it

may not actually be out for another year. But

this is kind of a status, they're done with

this, it was completed almost a year ago.

They moved on to the third plant

now. So this is probably where it will be, it

will just be a subset of a much larger document.

MR. GIRARD: Thank you.

MR. KIM: I have one follow-up

question.

Mr. DePriest, was it your

testimony that, even without carbon injection,

that there -- you would expect to see

variability as far as particulate matter?

MR. DePRIEST: Oh, absolutely, yes.

MR. KIM: Okay. Thank you.

HEARING OFFICER: Question 17.

MR. KIM: Thank you.

L.A. REPORTING (312) 419-9292

1197

HEARING OFFICER: Thank you,

Mr. Nelson.

MR. BONEBRAKE: I'm just wondering,

we've been at it for about an hour and 40. Time

for a break?

HEARING OFFICER: I'd like to go

another ten minutes or so.

MR. DePRIEST: Question 17.

On Page 11 you also state that:

"The capabilities of these existing ESPs to

capture these sorbents without exceeding

particulate/opacity limitations will vary

significantly across the coal-fired units in

Illinois."

Question A. Does that suggest

that you believe that some units will have

acceptable performance while others do not?

My answer is, it is possible,

although guarantees may not be available from

suppliers.

Question B. Doesn't the temporary

technology-based standard address the concerns

for those that may have difficulty?

And my answer is, the TTBS

L.A. REPORTING (312) 419-9292

1198

provides limited relief, but only for a fraction

of the units. We do not know if this will be

sufficient.

HEARING OFFICER: Question 18.

MR. DePRIEST: Regarding your stated

concerns on Pages 12 through 14, No. 2 through

No. 6, are these not largely the result of your

client's position that the only way to comply

with the proposed Illinois Rule is by

retrofitting fabric filters on every unit?

My answer is, the concerns would

apply to any individual unit that would require

a fabric filter or compliance. In other words,

where the ESP would not be able to achieve

mercury capture.

HEARING OFFICER: Go ahead, Mr. Kim.

MR. KIM: So, I guess, to turn that

answer around, if compliance with the Illinois

Rule were possible without the need for a fabric

filter, would those stated concerns that were

identified largely go away?

MR. DePRIEST: Oh, yes, they would.

Right.

HEARING OFFICER: Question 19.

L.A. REPORTING (312) 419-9292

1199

MR. DePRIEST: Question 19.

Regarding your stated concern

No. 7, "Waste Disposal Limitations," if a fabric

filter is used as you have testified power plant

owners believe it's necessary, does this concern

not largely go away?

Answer, with the mercury-specific

fabric filter, the waste disposal concern goes

away if the existing precipitator can be kept in

service to capture the fly ash prior to carbon

injection. Clearly, the spent activated carbon

injection captured in the fabric filter would

need to be disposed of if the contamination of

all the fly ash would be avoided.

No. 20. Regarding your stated

concern No. 7 -- same thing. And your

statement, "If the existing ESP is used to

collect the mercury sorbent, the operator will

need to make the necessary provisions for

landfill of the unmarketable fly ash, with the

attendant costs and secondary environmental

risks."

Do you agree that these additional

costs are already included in the estimated cost

L.A. REPORTING (312) 419-9292

1200

of the rule in the Technology Support Document?

I have not done a detailed analysis of

the Technical Support Document to determine

whether the costs are realistic, but understand

that it was the intent to account for landfill

costs in that document. We understand that

another witness is addressing, or I guess did

address, this ash disposal issue yesterday.

No. 21. Regarding your statement

on Page 15, "Current projections for flue gas

desulfurization projects required to meet the

SO2 requirements of Phase I of CAIR will require

the installation of over 150 new FGD systems

representing over 60,000 megawatts of coal-fired

capacity in the U.S. These new FGD systems will

go into service between 2006 and 2010 and

represent a market that is more than seven times

the size of that which was achieved in all of

the 1990s.

"This environmental market, in

conjunction with the ongoing SCR program for NOx

and the accelerating construction of new

coal-fired plants across the country, is

straining the capabilities of industry resources

L.A. REPORTING (312) 419-9292

1201

to keep up with both the quality and quantity

demands of the utility industry."

Question A. If it were possible

to comply with the Illinois Rule through sorbent

injection alone, without the need for fabric

filters, except on the two units with hot-side

ESPs, would that not largely mitigate the issues

you discuss here and in the following pages

through Page 20?

And my answer is, yes, if it was

possible to comply with sorbent injection alone.

Question B. With specific regard

to your statement "These new FGD systems will go

into service between 2006 and 2010 and represent

a market that is more than seven times the size

of that which was achieved in all the 1990s," do

you think suppliers of FGD technology consider

the 1990s a particularly robust period of

business, or would it be better characterized as

somewhat of a disappointing level of FGD

activity?

Wasn't the '90s a fairly slow

period for the scrubber business with most of

the compliance activity associated with coal

L.A. REPORTING (312) 419-9292

1202

switching?

My answer: We are not able to

speak for the FGD system suppliers' perspective

on the 1990s. We do know that the major FGD

suppliers have indicated that the current market

is extraordinarily busy and that their ability

to respond to all requests for equipment has

become very limited.

Question C. In contrast to the

low level of FGD business in the 1990s, roughly

how many megawatts of coal-fired SCR systems

were installed in the period 1998 through 2005?

My answer is, I do not have these

figures immediately available, but I believe

that -- and I may be wrong here -- I believe

that Mr. Cichanowicz has spoken to this issue in

the previous couple of days. And I do

understand that the U.S.EPA has information

along the lines of your request.

Now, I can say, as an additional

comment, that Sargent & Lundy worked on 53

different SCR projects during that time frame.

And then, of course, there was a number of other

ones going on.

L.A. REPORTING (312) 419-9292

1203

HEARING OFFICER: D.

MR. DePRIEST: D. Roughly how many

combined cycle plants, which nearly all required

SCRs and many man hours of boilermaker craft

labor, were brought on line in that same period?

Again, I do not have the answers

to these figures particular -- I do not have

these figures. But there is no comparison

between the labor requirements for a combined

cycle construction and coal plant construction

and retrofit projects.

HEARING OFFICER: E.

MR. DePRIEST: E. By and large, were

these air pollution control projects, admittedly

costly and difficult, performed satisfactorily

by the air pollution control industry?

Yes. But, as discussed, an

unprecedented number of projects will be

competing for, essentially, the same resources

that were available in the 1990s. Granted,

these resources are responding to the demand of

expansion of their capabilities, but the strain

is evident and a significant concern to all that

participate in this business.

L.A. REPORTING (312) 419-9292

1204

F. Doesn't the air pollution

control industry include some of the largest

pollution control companies in the world?

My answer: Even the largest air

pollution control companies have indicated to us

that they are being selective about which

projects they bid due to the busy market.

Also, many of the air pollution

control companies are not in the business of

actually fabricating or constructing their own

equipment, and therefore, rely heavily on other

less substantial companies for many of their

system components.

HEARING OFFICER: Mr. Kim.

MR. KIM: Oh, I was going to say -- I

was jumping ahead to No. 22, and I was going to

say that I think it's already answered. But if

Mr. Harley has a follow-up...

HEARING OFFICER: Mr. Harley.

MR. HARLEY: In your statement on

Page 15, which was quoted in the question, these

upgrades in pollution control equipment are

represented as being done in order to satisfy

CAIR requirement; is that correct?

L.A. REPORTING (312) 419-9292

1205

MR. DePRIEST: Well, I think,

principally, you're right. Principally CAIR.

There are other projects that are ongoing for

other reasons, but principally CAIR.

MR. HARLEY: And regardless of whether

or not there were a Mercury Rule, either on the

federal or state level, it would still be

required to make these upgrades in order to meet

the requirement of CAIR; is that correct?

MR. DePRIEST: That's correct.

MR. HARLEY: And later you talk about

upgrades which are being done in the industry --

pollution control equipment offerings that are

being done in the industry, in order to meet NOx

requirements; is that correct?

MR. DePRIEST: That's correct.

MR. HARLEY: And those upgrades would

have to be done by utility operators, regardless

of whether there were a Mercury Rule or not; is

that correct?

MR. DePRIEST: That's correct.

MR. HARLEY: Of the 150 new FGD

systems which are being installed, are you aware

of any which are being installed in Illinois?

L.A. REPORTING (312) 419-9292

1206

MR. DePRIEST: Yes, I am.

MR. HARLEY: And those projects are

being done in order to satisfy CAIR

requirements; is that correct?

MR. DePRIEST: Well, I think it's

public knowledge that Dynegy is operating under

a consent agreement on another subject, but they

also have CAIR requirements also. So whether or

not they're doing it for CAIR -- they're doing

it, nonetheless.

MR. HARLEY: It's correct then to

state that CAIR imposes an independent set of

requirements that will lead to pollution control

upgrades at many electric generating units

across the country?

MR. BONEBRAKE: Independent of the

Mercury Rule?

MR. HARLEY: Yes, that's correct.

MR. DePRIEST: That's correct.

MR. HARLEY: And requirements relating

to NOx, will, similarly, create an independent

basis for significant investment in pollution

control equipment and coal-fire power plants

across the country, by independent, and

L.A. REPORTING (312) 419-9292

1207

Mr. Bonebrake will clarify, independent of what

the Mercury Rule would apply to?

MR. DePRIEST: That's correct.

MR. HARLEY: Thank you.

HEARING OFFICER: And I agree with you

that No. 22 has been answered. So let's go on

to 23 and we'll take a break.

MR. BONEBRAKE: I'm wondering if 23

has also been answered, at least in part,

because there was some discussion earlier about

assessments that had been done for various

companies.

MR. KIM: I would agree that 23A,

likely, has been asked and answered. And

assuming that for proprietary concerns, would

continue to be an issue, likely 23B has been

asked and answered.

I'm assuming 23C has been asked

and answered and I don't know that 23D has.

MR. DePRIEST: It's going to be the

same answer, but I'll read it.

MR. KIM: Okay.

MR. DePRIEST: What are the expected

reductions, if any, in mercury emissions in

L.A. REPORTING (312) 419-9292

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pounds reduced per year, presented to reduce per

year from a given base year as a result each

plant's federal CAMR compliance strategy in

Phase I, same question for Phase II of CAMR.

Please use a year from 2002 to 2005 as the base

year available. If not, please identify the

base year.

MR. BONEBRAKE: I first just wanted to

put an objection on the record that the question

seems to assume that each plant, I'm assuming

that's in Illinois, has a federal CAMR

compliance strategy in place. And I don't know

if there's been any factual predicate for that.

And I don't know if these

witnesses' positions speak to what all of the

companies have done or are doing given prior

testimony about providing data but not specific

to certain companies. So there's some

foundation assumptions that are built into this

question that I think are either open or

inconsistent with the testimony to this point.

MR. KIM: And I think, as long as the

question -- the context of the question is

limited to companies that you have identified

L.A. REPORTING (312) 419-9292

1209

previously as being clients of yours, then I

think, you know, with that understanding, that I

think Mr. Bonebrake's concern would be resolved.

MR. BONEBRAKE: You can go ahead and

answer.

MR. DePRIEST: Does that require an

answer?

MR. KIM: Well, no. I'm just saying

that we would agree that if you do agree that

your answer is conditioned on the fact that

you're only answering as to the companies that

are clients of yours; is that correct?

MR. DePRIEST: Yeah, and I probably

won't answer it.

MR. KIM: The nonanswer answer you're

providing.

MR. DePRIEST: I'm just looking at the

detail here, and I guess we go back to my

earlier testimony on this subject.

If you look at the work that we

did for Dynegy and Midwest Gen, we specifically

developed the cost performance, O&M, capital,

et cetera, to the application of a host of

different technologies and all their sites. We

L.A. REPORTING (312) 419-9292

1210

didn't make those type of calculations you're

talking about as to, you know, how many pounds

of mercury might have been reduced or in their

strategy, because we didn't develop a strategy.

MR. KIM: The only one follow-up I

have then is just to go back and clarify.

I think you testified earlier when

you did this analysis work -- well, maybe you

can clarify for me.

You testified that you had done

some analysis work on a plant by plant basis, I

believe, to determine how they stood and

compared with CAIR/CAMR and the Illinois Mercury

Rule; is that correct?

MR. DePRIEST: I'd said the assessment

that we did was the assessment of what it would

cost capital and O&M-wise to apply a technology

to that station to perform in a fashion of

either reducing SO2, NOx or mercury. But not an

assessment of how that particular station might

fit into their overall strategy for compliance

of the rule.

MR. KIM: And when you say "the rule,"

the three rules that I just described?

L.A. REPORTING (312) 419-9292

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MR. DePRIEST: That's correct.

MR. KIM: Okay.

Nothing further on that question.

HEARING OFFICER: All right.

Then let's take a short break,

about ten minutes, and come back and finish.

(WHEREUPON, a recess was had.)

HEARING OFFICER: And I believe we are

on Question No. 24.

MR. DePRIEST: Question No. 24.

Have you conducted an assessment

of which coal-fired power plants and electric

generating units in Illinois would likely delay

or completely avoid installation of mercury

controls, such as they would need to purchase or

use bank allowances for a period under the

federal CAMR Rule due to installation of

controls being uneconomical, difficult or for

any other reason?

And I think, you know, in a way

I've kind of answered this before, in that we

developed the costs and the capital and O&M

costs and performance expectations for the

application of technology to all the units in

L.A. REPORTING (312) 419-9292

1212

question. But we did not develop a strategy

that said you're going to operate this one with

the technology and that one without and

therefore answer this question.

I do not know the answer to that

question. That particular strategic plan was

developed by the utility itself.

MR. KIM: So that is separate from --

that's all right, strike that.

HEARING OFFICER: Do you have an

opinion, though, that there are utilities out

there that it's so uneconomical, difficult to

even meet the CAMR requirements, they would have

to purchase allowances?

MR. DePRIEST: Well, yeah. Operating

under CAMR, I think it's pretty clear, even

though not absolute, that the smaller units,

older, less heavily used units, would probably

be the best candidates for those not to put

technology on and to rely on over compliance

and/or the purchase of allowances from other

units, mainly because of the cost benefit of

applying expensive technology and capturing very

few pounds of mercury, it just doesn't make

L.A. REPORTING (312) 419-9292

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sense.

HEARING OFFICER: Mr. Kim.

MR. KIM: But those smaller, older

units that you described, at least in Illinois,

those would be the units that would potentially

be eligible to participate under the TTBS

provision of the Illinois Rule; is that correct?

MR. DePRIEST: That's correct. As I

mentioned earlier, that's a -- some additional

flexibility is nice to have, even though it may

or may not accommodate all the nuances that we

might encounter.

MR. KIM: Thank you.

HEARING OFFICER: Twenty-five.

MR. BONEBRAKE: I think 25 has been

answered by his answer to 24.

MR. KIM: That's correct.

MR. BONEBRAKE: And I believe 26, as

well. Does that relate back to Question 24;

Mr. Kim?

MR. KIM: Yes. We would agree.

HEARING OFFICER: Twenty-seven.

MR. DePRIEST: Twenty-seven. What

would be the actual "additional and financing

L.A. REPORTING (312) 419-9292

1214

costs" associated with installing a baghouse six

years early, as referred to on Page 6 of your

testimony?

And the answer is, the cost would

be the interest costs associated with the

capital budget, and, of course, the cash flow

for spending that budget, but for each unit

subject to the current interest rates available

to the specific unit owner. So I would expect

that number would be different for every unit

and for every different utility, depending on

their ability to borrow money to finance the

project.

It's, essentially, financing it

and installing it earlier than they have to.

HEARING OFFICER: Question 28.

MR. DePRIEST: Twenty-eight. Please

provide documentary evidence of the "conclusion"

of the owners of the Illinois' electric

generating units, including the lack of

precipitator margin as discussed on Page 10 of

your testimony.

I believe we have gone over this

in quite a bit of detail.

L.A. REPORTING (312) 419-9292

1215

MR. BONEBRAKE: I think the sentence

in question was referenced in an earlier

question, as least as I understood this

question.

MR. KIM: So your answer, I guess,

would be what? Would this --

MR. DePRIEST: I think you'd probably

go all the way back to the answer to Question

No. 6.

MR. KIM: Okay.

HEARING OFFICER: Twenty-nine.

MR. DePRIEST: What ESP upgrade

projects have Sargent & Lundy been involved with

for existing ESPs other than adding additional

collection area? See Page 12 of the testimony.

My answer is, we do not track our

experience according to which modifications

added collection area and which did not.

However, our total experience includes 84

precipitator retrofits to existing boilers,

precipitator performance improvement at 85

different existing units, 20 of them since 1990

and precipitator structural improvements at

42 units.

L.A. REPORTING (312) 419-9292

1216

MR. KIM: Is that Illinois specific or

is that your national clientele?

MR. DePRIEST: It's the national

clientele.

MR. KIM: Do you have a breakdown as

far as Illinois clients on that answer?

MR. DePRIEST: I could get that for

you if you'd like, I do not have it with me.

MR. KIM: Maybe a written comment,

that might be helpful to us.

HEARING OFFICER: Yes, please.

Mr. Harley.

MR. HARLEY: In performing these ESP

retrofit projects, modification projects, is it

ever necessary to install additional ductwork?

MR. DePRIEST: It might be. Some of

the upgrades and/or retrofits -- certainly the

retrofits -- would be additional ductwork.

The upgrades would include

additional ductwork if we had to modify the

field with a precipitator in some fashion that

it ended up changing the arrangement of the

ductwork coming through or leaving the

precipitator.

L.A. REPORTING (312) 419-9292

1217

MR. HARLEY: And so this could include

installing extensions of existing ductwork?

MR. DePRIEST: If the arrangement

dictated that.

MR. HARLEY: Thank you.

HEARING OFFICER: Off the record.

(WHEREUPON, discussion was had

off the record.)

HEARING OFFICER: Back on.

Question 30.

MR. DePRIEST: Do electrical upgrades

to the electrical system at a power plant

provide an opportunity for electrical

reliability or efficiency improvements? See

page 12 of the testimony.

Generally, these types of upgrades

are undertaken, at least with regard to

environmental system upgrades, to handle the

specific additional loads of the fans and other

environmental-related control equipment.

Certainly, we would take the opportunity to

improve electrical reliability if there were

existing issues that could be resolved with

economic justification. However, these

L.A. REPORTING (312) 419-9292

1218

opportunities for improvement are very rare.

HEARING OFFICER: Thirty-one.

MR. DePRIEST: Thirty-one. Are outage

schedules adjusted when unforeseen problems

arise with a generating unit?

The answer is, unit owners will

take unscheduled outages when unforeseen

problems arise, but only when absolutely

necessary for as short a period as possible, due

to the financial losses associated with being

offline.

HEARING OFFICER: Thirty-two.

MR. DePRIEST: How many new FGD

systems will be installed in 2008 and 2009 in

Illinois out of the 150 new FGDs identified in

your testimony?

And the answer is, the Illinois

utilities' plans to install FGD units are

confidential to the owners, and this question

would be best directed to them. But I would

add, you know, I think Ameren made it pretty

clear which ones they intend to do, Dynegy has

publically announced which ones they intend to

do.

L.A. REPORTING (312) 419-9292

1219

So the information is available

and is becoming more public, I think.

HEARING OFFICER: So you can't,

generally, answer how many of the 150 are

Illinois based?

MR. DePRIEST: I can add them up in

my -- I can think of 12.

MR. KIM: Can you -- I don't have the

numbers available, as happens. Can you give a

breakdown of the 12, how those were assigned by

company? You said you identified Ameren and

Dynegy.

MR. DePRIEST: You know, Dynegy has

identified four.

MR. KIM: Right.

MR. DePRIEST: And it's clear, the

consent decree, obviously, says what it says.

MR. KIM: Sure. I guess what I'm

saying is, I guess, looking at it this way,

aside from Ameren and Dynegy, and probably a

balance, do you know what the remaining FGDs

would be, who is going to be responsible for

those outside of Ameren and Dynegy?

MR. DePRIEST: Well, I think if they

L.A. REPORTING (312) 419-9292

1220

build that unit in Dallman, there's going to be

a scrubber in that one, include that one in the

list. I'm trying to think, I don't think

there's anybody else.

I mean, Midwest Gen hasn't decided

what they're going to do. Prairie State, if

they build that, of course, there will be a

scrubber and associated equipment on that one.

HEARING OFFICER: Mr. Harley.

MR. HARLEY: In your prefiled

testimony on one of the final pages, you

indicate that an FGD, in combination with carbon

injection, is likely to meet the requirements of

both CAMR and also the Illinois Rule.

Do you recall that?

MR. BONEBRAKE: Can you point us to a

particular page, Mr. Harley?

MR. HARLEY: Yes, I can.

HEARING OFFICER: I think Page 25,

Mr. Harley.

MR. HARLEY: Correct, Page 25. It's

the first sentence.

MR. DePRIEST: Oh, where I say

implementation of dry FGD with a fabric filter

L.A. REPORTING (312) 419-9292

1221

for CAIR, SO2 compliance?

MR. HARLEY: That's correct.

MR. DePRIEST: In conjunction with a

sorbent injection. Achieved in mercury control

compliance with CAMR.

MR. HARLEY: Please continue reading.

MR. DePRIEST: And should achieve

compliance with the proposed Illinois Mercury

Rule.

MR. HARLEY: Thank you, that's fine.

In coming up with your cost

estimates, where you have a piece of technology,

like an FGD, which will both help achieve CAIR

compliance and also will provide a co-benefit of

additional mercury control, how did you allocate

out in making your cost estimates? What portion

of the cost of installing that FGD should be

allocated to mercury compliance alone?

MR. DePRIEST: We did not allocate.

We didn't try to differentiate the dollars that

might go through SO2 control and specific

technology.

We simply identified the costs of

their technology, capital and O&M, and what we

L.A. REPORTING (312) 419-9292

1222

expected its performance to be, SO2 and mercury.

MR. HARLEY: And so, if you were asked

to provide an estimate for mercury control

alone, you would include both the carbon

injection system and also the total cost of the

FGD unit?

MR. DePRIEST: Well, we didn't perform

that exercise. I guess we could, even though

I'm not sure it would make sense.

MR. HARLEY: Thank you.

HEARING OFFICER: A.

MR. DePRIEST: A. Why would

50 percent of Illinois' coal-fire generators

take an outage in the spring of 2009?

Every unit that would require

fabric filters to meet the proposed rule, would

need to take an outage in early 2009. The

50 percent figure was used to illustrate the

potential impact if installation of fabric

filters affected only half of the Illinois

units.

B. Why would this affect power

availability if outages were staggered?

The outages can only be staggered

L.A. REPORTING (312) 419-9292

1223

up to a point, due to the outage duration

required, and due to the long lead time for

fabric filter equipment.

Essentially, what I'm saying there

is the long lead times for fabric filter

equipment and design pushes us all into the

spring of 2009 as to when we would be able to

cut these into service, and it would all happen

at once.

MR. KIM: I have only one follow-up.

And it's not in response to this, but it just

tags up to some of the earlier testimony.

And that was, I believe you

testified that you gave some dates as to when

your company began doing assessment work for

Ameren, Midwest Gen and Dynegy. For example, I

think Ameren you said began in 2003, 2004.

And I believe you testified that,

since that time, you have been updating the

information; is that correct?

MR. DePRIEST: That's correct.

MR. KIM: Could you just describe what

you meant by "updating"? In other words, what

actions are you taking or what kinds of things

L.A. REPORTING (312) 419-9292

1224

are you taking into account when you update

information? Starting from that initial --

whatever your initial results of your

assessment.

MR. DePRIEST: Well, if you look at

the market forces that are in play here, to go

back to 2003, we started seeing some inklings of

resource constraints in which we're driving the

costs up, particularly in the craft labor area.

And so as we moved along, taking that component

of our cost estimates and advised our clients as

to how that has changed since the initial work

that we have done. That's one way.

Other ways that are, you know,

probably a little more concrete, would be to

actually take bids for some of the hardware,

especially if you look at the work we're helping

Dynegy with on the FGD program with the fabric

filter. Some of those projects are actually

under contracts, so those costs are much more

firm today than they were when we initially

started that work.

MR. KIM: Would those updating

activities include revised cost estimates to

L.A. REPORTING (312) 419-9292

1225

reflect changes or improvements in different,

for example, carbon injection technologies?

MR. DePRIEST: Principally, in that

the -- I'm trying to think of these -- in some

cases it would be true. When we've included the

requirement in our contract that the devices

that we're purchasing actually do some mercury

control, then it would.

Now, there's been a number of

cases where we've purchased, or are under

contract for FGD systems and fabric filter

systems that don't require -- currently have a

requirement in the contract for mercury control,

so those would not. But those that did would.

MR. KIM: And is this updating done on

an as-requested basis by the client, or is

this -- how is this -- is there just sort of an

understanding or a periodic kind of thing?

MR. DePRIEST: Well, we work very

closely with these clients, so I guess you'd say

it would be an on as-requested basis.

MR. KIM: That's all I have.

HEARING OFFICER: Mr. Bonebrake.

MR. BONEBRAKE: I did have a couple of

L.A. REPORTING (312) 419-9292

1226

follow-up questions.

I think you mentioned the term

lead time in connection with baghouse

installation in a prior answer. Can you

describe for the Board what lead time means and

what the lead time period, generally, would be

for baghouse installation at this particular

point in time?

MR. DePRIEST: If baghouses were

required for compliance with the 90 Percent

Rule, we look very closely at the lead time

required to get those into place on the Illinois

units. And our assessment, speaking to the

equipment suppliers, would be that it's

somewhere in the neighborhood of 30 months,

maybe a little bit more, from time of actual

award to the equipment supplier to where he

would have his equipment operating at commercial

fashion.

So you have to put a few months in

front of that, for us to write a spec and do

some studies in order to define the hardware

that we intend to purchase.

So it's somewhere between 30 and

L.A. REPORTING (312) 419-9292

1227

36 months from get started to inservice and

running commercially. So if you look at the

schedule of a November of this year's final rule

and then we get started on that date, and then

we have a July of 2009 commercial operation

date, it pretty much says that we're doing

everything in the spring of 2009, from the

standpoint of cutting it in to the existing

equipment and infrastructure at the site.

MS. BASSI: Mr. DePriest, does that

time include permitting?

MR. DePRIEST: It should be adequate

to cover permitting.

MR. KIM: Because we're very quick

with that.

MS. BASSI: Yeah, right.

MR. DePRIEST: I was going to say, I'm

sure you'll be very cooperative.

MR. BONEBRAKE: One other follow-up,

Mr. DePriest. Mr. Harley earlier asked you some

questions regarding obligations to install NOx

and SO2 control technologies under CAIR. And as

you consider CAIR requirements, does the

Illinois Rule pose some technical and cost

L.A. REPORTING (312) 419-9292

1228

challenges that CAMR does not, because CAMR

permits trading while the proposed Illinois Rule

does not?

MR. DePRIEST: Clearly, the CAMR Rule

that has a trading program involved in it offers

a lot more flexibility to utilities to find the

compliant strategy. And, in my opinion, it also

significantly reduces the risk of lack of

performance of a mercury-controlled technology

applied to these coal units.

So if you look at the Illinois

Rule, if the technology you put in, as currently

proposed, could put in -- did not achieve the

90 percent reduction, there's virtually no

recourse as to -- the way I read it -- as to an

alternate solution. Whereas, the CAMR Rule, if

you put in a technology expecting it to do

75 percent reduction of mercury and it only did

65 percent reduction, well, then you just go to

the market -- the mercury allowance market and

purchase some allowance to cover your shortfall.

So the risk is significantly

different with the CAMR Rule than it is with the

proposed Illinois Rule.

L.A. REPORTING (312) 419-9292

1229

HEARING OFFICER: Mr. Harley.

MR. HARLEY: Just one further question

to help clear the record up a little bit. You

had previously testified in response to

Mr. Nelson's inquiry about your knowledge of the

use of brominated carbon injection. And

although you were not personally aware of this

results, there were individuals within your firm

who were aware of those results and would be

keeping your clients up to date on those

results. For purposes of the record, can you

identify who those individuals are?

MR. DePRIEST: Sure. Rise Gatewadd is

one, Paul Farber is another, Steve Catsberger in

another, Dave Sloat (phonetic). I could get you

my work chart.

MR. HARLEY: No, that's fine. Thank

you very much.

HEARING OFFICER: Mr. DePriest, I also

note that Prairie State Generating Company filed

a couple of questions for you. And although we

may have touched on them, I'm not sure we

specifically answered them.

The first question from Prairie

L.A. REPORTING (312) 419-9292

1230

State was, what are the technical problems of

reducing mercury emissions from high sulphur

coal?

MR. DePRIEST: Yes. And I have a

answer.

The most significant problem of

mercury control with ACI and high sulphur coals

is the potential for a high level of SO3

occurring naturally in the combustion process or

being formed in the SER reaction, interfering

with the absorption of mercury on the surfaces

of the activated carbon.

HEARING OFFICER: Thank you.

MR. DePRIEST: I see that as being

the -- by far, the most significant technical

issue on high sulphur coal.

HEARING OFFICER: And the second

question, go ahead and read it in.

MR. DePRIEST: Has it been

demonstrated that 90 percent mercury control of

high sulphur coals can be achieved over the long

term? If not, what level of control do you

believe is possible?

And my answer is, no long-term

L.A. REPORTING (312) 419-9292

1231

demonstration of mercury control on high sulphur

has been documented. In all likelihood, wet FGD

systems on high sulphur coal, have been

capturing a significant quantity of the oxidized

mercury in the flue gas, although, there is

little data showing this over a long period of

time.

However, there are still some

significant questions to be answered regarding

FGD capture of mercury, including, one,

potential for readmissions due to reduction of

oxidized mercury in the FGD system. Two, degree

of oxidation of mercury in the flue gas and its

dependence on coal chemistry.

Three, the impact of various

additives to the fuel on its oxidation level.

Four, the impact of oxidation catalyst on

mercury oxidation.

And Five, other -- I just threw in

kind of a broad thing -- other developing

technologies to promote oxidation and facilitate

capture in the FGD system. Therefore, there is

no one answer to this question and it will be

evolving as more development of technology

L.A. REPORTING (312) 419-9292

1232

occurs.

HEARING OFFICER: And I -- just as a

point of clarification, you talked about

long-term testing. What would you consider a

long-term testing, what length?

MR. DePRIEST: Depending on the

technology involved, I think, you know,

operation, let's say, with activated carbon

injection and upstream of a fabric filter. I

would expect somewhere in the neighborhood of a

year or more would be required to fully

understand the impact that activated carbon

injection has on bag life, for instance, because

the cleaning process of the bag is what really

determines its life.

And activated carbon, and its

ability to clean it off the surface of the bag,

is still not fully understood. And if we have

to clean the bags very frequently, we're going

to shorten the life of the bags, which might

drive us to the installation of a larger

baghouse to accommodate that to control bag

life. Because bag life is a significant cost

factor in O&M costs over the years.

L.A. REPORTING (312) 419-9292

1233

As far as injection into an ESP, I

think the testing requirements or demonstration

requirements are far shorter, because I think

we're going to know pretty soon whether or not

that works. And the only real variables are

variables in the ash chemistry that might affect

that.

So getting some experience, as I

mentioned earlier, the ash in coal is not very

consistent, it varies significantly over time.

And, you know, just to kind of get a feel for

how all those variations might be experienced in

the performance of mercury and particulates

captured, particularly, nine months -- maybe,

six, nine months.

It's hard to say. It's an

emerging issue, you know, we'll learn things as

we go.

HEARING OFFICER: Thank you.

Anything else?

MR. KIM: Thank you, Mr. DePriest.

HEARING OFFICER: Thank you very much,

Mr. DePriest.

Mr. Marchetti is next.

L.A. REPORTING (312) 419-9292

1234

Off the record.

(WHEREUPON, discussion was had

off the record.)

HEARING OFFICER: Before we have

Mr. Marchetti sworn in, I do want -- one

housekeeping thing to take care of. I marked

Exhibit 116 but had not entered it into the

record. I will enter it into the record.

116 was the chart from Mr. Nelson,

the Great River Energy's Stanton Station Unit 1

that had been taken from the draft report. I

marked it and Mr. Bonebrake had reserved an

objection, so I didn't actually enter it, so I'm

going to enter it into the record now.

(WHEREUPON, said document,

previously marked Exhibit No. 116,

for identification, was offered and

received in evidence.)

MR. BONEBRAKE: I would just make two

points on that document. First, I believe

Mr. Nelson testified that it was an extract from

a document, which itself is entitled Draft, and

second, I believe Mr. Nelson also indicated that

he had made at least one or two changes to the

L.A. REPORTING (312) 419-9292

1235

version of that document as set forth in the

report.

HEARING OFFICER: All right. Can we

have Mr. Marchetti sworn in, please.

(WHEREUPON, the witness was duly

sworn.)

HEARING OFFICER: And if there's no

objection, I will mark Mr. Marchetti's pretrial

testimony as Exhibit 118.

Seeing none, it's marked as

Exhibit 118.

(WHEREUPON, a certain document was

marked Exhibit No. 118 for

identification, as of 8/18/06.)

MR. AYRES: Mr. Marchetti, good

morning, afternoon, whatever it is.

MR. MARCHETTI: Yeah. Good day.

HEARING OFFICER: Mr. Marchetti, did

you want to give a brief summary, or did you

want to go directly to the questions?

MR. MARCHETTI: We can go directly to

the questions.

HEARING OFFICER: Okay.

MR. MARCHETTI: That would be a good

L.A. REPORTING (312) 419-9292

1236

start.

Question 1.

MR. AYRES: Could I ask a question

before he answers Questions 1?

HEARING OFFICER: Sure.

MR. AYRES: Because the decision was

not listed.

HEARING OFFICER: Sure.

MR. AYRES: And that's simply --

Mr. Marchetti, are you an economist?

MR. DePRIEST: I've done graduate work

in economics. And I've been doing environmental

economic policy analysis for about 25 years.

MR. AYRES: Are you a member of the

American Economic Association?

MR. DePRIEST: No, I'm not.

MR. AYRES: Okay.

MR. MARCHETTI: Okay?

MR. AYRES: You can go ahead,

Mr. Marchetti.

MR. MARCHETTI: Okay.

On Page 4 of your testimony, you

describe the control options in the

Emission-Economic Modeling System model.

L.A. REPORTING (312) 419-9292

1237

A, please describe the cost and

operational assumptions for each of the emission

control technologies listed on Page 4 of your

testimony, specifically as implemented in the

EEMS model analysis.

The cost and operational

assumptions that were the basis into the EEMS

are discussed in detail in Appendix A, mercury

controls, and Appendix B, SO2, NOx control of

Ed Cichanowicz's testimony. The mercury control

assumptions begin on Page 55 of Ed Cichanowicz's

testimony and conclude on Page 74 and

assumptions defining SO2/NOx/PM controls begin

on Page 75 and conclude on Page 91 of

Ed Cichanowicz's testimony.

HEARING OFFICER: Mr. Marchetti, could

you slow down a little bit?

MR. MARCHETTI: Oh, sure.

MR. AYRES: Maybe get the mic a little

closer, it's hard to hear over here.

MR. MARCHETTI: Let me just put this

over here. I will start all over.

HEARING OFFICER: For the record, when

he says EEMS, it's E-E-M-S.

L.A. REPORTING (312) 419-9292

1238

MR. MARCHETTI: Okay. Question A.

Please describe the cost and

operational assumptions for each of the

emissions control technologies listed on Page 4

of your testimony, specifically as implemented

in the EEMS model analysis.

Response. The cost and

operational performance assumptions that were

incorporated into and discussed in detail in

Appendix A, Murphy controls and Appendix B, SO2

and NOx control of Ed Cichanowicz's testimony.

The mercury control assumptions begin on Page 55

of Ed Cichanowicz's testimony and conclude on

Page 74. The assumptions defining SO2/NOx/PM

controls begin on Page 75 and conclude on

Page 91 of Ed Cichanowicz's testimony.

HEARING OFFICER: B.

MR. MARCHETTI: B. Please provide

specific environmental retrofits selected by the

model for each coal-generating unit in Illinois

along with the associated capital and variable

operating costs.

Response. We are providing the

technology assignments for CAIR/CAMR and CAIR

L.A. REPORTING (312) 419-9292

1239

Illinois Rule, as exhibits.

MR. ZABEL: This one (indicating)?

MR. MARCHETTI: Yes.

HEARING OFFICER: The first document

is CAIR-CAMR tech. And I'll mark this as

Exhibit 119, if there's no objection.

MR. AYRES: Madam Chairman, I would

just note that this document, along with a

number of others, was requested in our written

questions. And receiving it the moment before

the testimony is given makes it very difficult

for us to respond to.

We would like to have the

opportunity to study the document. And I'm sure

we're going to get in the stream today before

our opportunity to cross-examine this witness is

closed.

HEARING OFFICER: Within reason, I'm

willing to allow that. I would just --

MR. ZABEL: That pattern was set in

Springfield, Madam Hearing Officer. Our written

questions asked for documents, we did not get

any in advance.

We assumed that would be the

L.A. REPORTING (312) 419-9292

1240

pattern following throughout. And there was, of

course, much less time to prepare these than to

prepare the documents requested in the written

questions used in Springfield.

HEARING OFFICER: And that's why my

answer is within reason, we'll allow that.

MR. AYRES: This set of assumptions,

for example, were clearly available some time

ago, because these are the assumptions that were

within the model, which the results of which you

had, so...

MR. ZABEL: As were the IPM briefs

that we asked for.

HEARING OFFICER: Let's just agree

that in this proceeding there's been a lot of

documents handed out at the hearing without the

opportunity for either side to -- and as I said,

within reason, I will allow you to cross -- will

allow you some leeway on cross-examination. I

loathe to ask Mr. Marchetti to come back on

Monday, for example, to answer any additional

questions.

So, within reason, we will try to

do that. I also remind you that, certainly, any

L.A. REPORTING (312) 419-9292

1241

comment you have on this information is gathered

and can be filed in comments later on, if not,

by the end of the process in this hearing.

MR. ZABEL: Thank you.

HEARING OFFICER: So I've now been

handed CAIR-IL -- which I assume is Illinois --

Rule Tech. And if there's no objection, we'll

mark this as Exhibit 120.

Seeing none, it's Exhibit 120.

(WHEREUPON, a certain document was

marked Exhibit No. 120 for

identification, as of 8/18/06.)

MR. MARCHETTI: However, we cannot

provide capital and O&M costs for these

technology assignments, other than in the

aggregate. Some unit specific costs then would

develop from proprietary data from individual

generators, and this data was not even shared

among the Illinois generators.

So what I'm saying is that we

did -- in doing this analysis, we did receive

some proprietary data from various generators in

the state.

MR. AYRES: And can you identify which

L.A. REPORTING (312) 419-9292

1242

companies that was from?

MR. MARCHETTI: Yeah. Midwest

Generation, Ameren and Dynegy and Kincaid.

HEARING OFFICER: Proceed.

MR. MARCHETTI: Okay. C.

Also on Page 4, you describe the

rationale for "50 Year Old Rule." Please

explain what you mean by a major capital

investment in this context.

What I would mean by a major

capital investment are improved investments in

FGD, SCR, SNCR, ACI and COPH systems installed

on a coal-fired power plant.

HEARING OFFICER: Mr. Marchetti, I

think, because you're looking down this way

(indicating) when you read, it might be more

helpful if the microphone is on the other side.

MR. MARCHETTI: This way (indicating)?

Can you hear me now?

HEARING OFFICER: Yes.

MS. MOORE: Excuse me. How many

50-year-old coal-fired plants are in Illinois?

MR. MARCHETTI: I believe we have

about 51. Let me just get that number.

L.A. REPORTING (312) 419-9292

1243

MR. ZABEL: I think that's a later

question, but...

MS. MOORE: Is it? Okay.

MR. AYRES: I think it is later, not

much later.

HEARING OFFICER: Okay. We will defer

to that then.

MR. MARCHETTI: If the installation of

HPAC injection systems, as described by

Dr. Staudt and Mr. Nelson in their previous

testimony, were all that were required for a

given unit to meet the Illinois Rule, would you

consider this to be a major capital investment?

"If," of course, is a critical

word. And since I do not agree -- we did not

agree to Mr. Staudt's and Mr. Nelson's control

assumptions, because they did not take into

account other unit modifications, operational

constraints and performance associated with ACI,

I really can't respond to that question.

Twenty-one units, okay.

HEARING OFFICER: Mr. Harley.

MR. HARLEY: In Exhibit 115, which is

the prefiled testimony of Mr. William DePriest,

L.A. REPORTING (312) 419-9292

1244

on Page 21, he indicates that the estimated

installed cost of a sorbent injection system,

such as activated carbon injection system, to be

between 1.5 to $3 million per unit. Using those

figures, would you consider this to be a major

capital investment?

MR. MARCHETTI: Yes.

MR. HARLEY: On what basis?

MR. MARCHETTI: On the basis that, I

believe, anything that's -- in terms of the

capital investment of the operational control

costs that go into these types of systems, adds

to your generation costs. And I believe that

would be a major capital investment.

Specifically, if it's going to be

employed on a very small or older unit.

MR. HARLEY: Thank you.

THE VIDEOGRAPHER: Question No. 2.

MR. AYRES: I'm sorry, before we get

to Question No. 2, I'd like to ask some

questions about the 50 Year Rule.

HEARING OFFICER: Okay.

MR. AYRES: In the analysis that you

did, you're talking about this 50-year

L.A. REPORTING (312) 419-9292

1245

assumption. It's a little unclear to me,

exactly what that means in terms of what the

model does in 50-year old claims.

MR. MARCHETTI: Okay.

MR. AYRES: Does this mean that the

units are shut down --

MR. MARCHETTI: No. No. Let me just

explain this 50 Year Old Rule then.

It's a presumption we have in the

model that any unit that has to face a

compliance decision, if it's going to be greater

than 50 years old at that time, would not

receive a technology deployment, would not get

retrofitted. And, basically, under a cap and

trade regime, would buy allowances to meet

compliance.

And we have used this 50 Year Old

Rule with a number of simulations in a number of

states. But not many utilities have reviewed

our information, and no one has come back and

said, well, I think we should get 60 years or

something like that.

So I think we've had a consensus

that, among the people that have reviewed our

L.A. REPORTING (312) 419-9292

1246

outputs that the 50 Year Old Rule is kind of a

barometer about deployment and technology. And

the other, too, is that when you get units that

are 55, 60 years old, and you put any kind of a

major capital investment on it, you're probably

going to be covering that capital -- the unit is

going to have to be operating into the 65,

70-year-old range. And there's a question

whether that is going to be -- if that unit is

going to be economically viable with something

like that.

MR. AYRES: So could you answer the

question about what happens to the 50-year-old

units in your model?

MR. MARCHETTI: They buy -- under a

cap and trade system, they would buy allowances

to remain in operation.

MR. AYRES: And under the Illinois?

MR. MARCHETTI: And the Illinois Rule,

that rule is somewhat violated. And we do put

technology on those older units, because you

have to meet a much more stringent reduction

target.

MR. AYRES: And which Illinois units

L.A. REPORTING (312) 419-9292

1247

are shut down according to your model?

MR. MARCHETTI: No Illinois units are

shut down.

MR. AYRES: Would they be mothballed

or put out of service, or? I'm not sure of what

the technical term is.

MR. MARCHETTI: There were no -- let

me just repeat myself. In this particular

analysis, the generation forecast can be used --

that we used in our analysis, was provided by

Charles River, CRA International.

They ran a simulation CAIR/CAMR,

they ran a simulation CAIR Illinois Rule. They

used our control assumption as part of this

analysis.

No units will shut down, okay?

And no units will shut down.

MR. AYRES: Are you aware that the

Tennessee Valley has already recently installed

SCR and all nine units of the Kingston Plant

have been put online in '54?

MR. MARCHETTI: Yes.

MR. AYRES: All right. And likewise,

commitments made to the state of Massachusetts

L.A. REPORTING (312) 419-9292

1248

regarding the Salem Hardwood plants, units one

and two, are in service in '51 and '52?

MR. MARCHETTI: Yes.

MS. BASSI: Excuse me, what --

Mr. Marchetti just testified that his

assumptions are that there would be technology

added to 50-year-old plants, so what is the

point of your questions?

MR. AYRES: I think he testified that

it would be in some cases and not in others.

And --

MS. BASSI: I don't think that's what

he said.

MR. AYRES: His testimony pronounces

this 50 Year Old Rule, I'm just trying to

understand with it means. It's also true --

MR. ZABEL: How does that relate to

Salem? Your understanding of what 50 year old

means, how does it relate to Salem? I guess I

lost it.

MR. AYRES: This has provided a

generalization, which can be placed in this

model, which assumes that plants over 50 don't

do something, although I'm not exactly sure

L.A. REPORTING (312) 419-9292

1249

what.

MR. MARCHETTI: They do not -- let me

just clarify.

They do not deploy technology

under a capital trade regime. Under CAIR or

CAMR, where there's the availability of

allowances to be purchased, they would not

deploy the technology, they would buy allowances

to do some system-wide training.

Under the Illinois Rule, because

of the stringent reduction, which is

significantly more stringent than CAMR, we did

deploy technology on units greater than 50 years

old. I think I would believe that there were

like 21 units in Illinois that are greater than

50 years old in 2009.

I believe 20 of those units

received technology under the Illinois Rule.

MR. AYRES: Isn't it true that models

that are used for this tend to -- let me back

up.

Models, like the one used by

Ms. Smith, allocated reductions or buying up

credits to units, simply depending on the cost

L.A. REPORTING (312) 419-9292

1250

of control versus the cost of allowances?

MR. MARCHETTI: Yes.

MR. AYRES: They usually don't have a

50-year constraint, they simply look at the

costs; correct? There may be some correlation,

but that's not a factor?

MR. MARCHETTI: They may -- I don't

know what Dr. Smith's, in terms of her modeling,

in terms of what kind of presumption she has on

older units. Yes, they do look at the costs of

technology versus the costs of allowances, and

we do the same in that manner, too.

MR. AYRES: But you added another

variable.

MR. MARCHETTI: We added another --

because the model structures of NEMS, which is

Dr. Smith's model, and EEMS, which is ours, I

mean, you've got to switch the letters around.

Ours is a much more unit-specific analysis, and

you have much more unit-specific data than you

would probably find in a NEMS model, a much more

broader aggregate.

HEARING OFFICER: I didn't hear all

that, I'm sorry.

L.A. REPORTING (312) 419-9292

1251

MR. MARCHETTI: That our data in EEMS,

meaning emissions, we would get out of the

system is much more unit specific, whereas in

the NEMS model, from what I understand there's

much more aggregation in there because they do

much more broader national analysis.

MR. AYRES: Could we talk a bit about

that, the EEMS or EEMS model, I don't know which

way to pronounce it.

MR. MARCHETTI: Sure.

MR AYRES: E-E-M-S, all capital

letters. Has this model been benchmarked

against other models or historical market

behavior?

MR. MARCHETTI: No.

MR. AYRES: Is it in the public

domain?

MR. MARCHETTI: It's -- in terms of

what you mean by "public domain," has it been

used in other reports or in terms of other

rulemakings or?

MR. AYRES: Well, no. What I mean is

the IPM model.

I guess, to some extent, the

L.A. REPORTING (312) 419-9292

1252

Charles River associate models have been

published, they've been available for people to

comment on, make suggestions for, et cetera, for

some time.

MR. MARCHETTI: Yeah. The NEMS model

was first developed around 1997 and has been

used in a variety of analyses, and has been

discussed and used -- in going to the model, and

various kinds of rulemakings, reports on various

kinds of proposed rules or comments on the rules

since 1997.

MR. AYRES: Are any of those public?

I understand that you may have done an analysis,

which related to a proposed rule, but that

doesn't make your model up; does it?

MR. MARCHETTI: Well.

MR. AYRES: The public couldn't find

out how you got there.

MR. MARCHETTI: It depends on what you

term "public." I mean, like the ICF/IPM model

is out of the public domain, the EPA uses it in

a variety of other -- you know, agencies or

institutions use it, but it's published in a --

they do have a little write-up, a description of

L.A. REPORTING (312) 419-9292

1253

the model.

And in terms of public, it's a

proprietary model. If you're asking for the

computer code or something, you're not going to

get it.

MR. AYRES: It has been tested against

historical market behavior, though; hasn't it?

MR. MARCHETTI: I cannot answer that.

MR. AYRES: So your model is,

certainly, a lot less available to the public

than, say, the IPM model?

MR. MARCHETTI: Yes.

MR. AYRES: Could you please tell us

the source for the cost estimates for mercury

controls in your analysis?

MR. MARCHETTI: The sources of control

estimates, I guess, you could find, you know, in

Appendix A. For the various tables that

Cichanowicz developed to develop the various

kinds of control assumptions and the cost

assumptions that went into an analysis.

Let me further clarify that we

were provided some specific information by

Midwest Gen, Dynegy, Ameren, for the control

L.A. REPORTING (312) 419-9292

1254

costs, and they were -- which is that

proprietary information I mentioned earlier.

And that information was also incorporated into

the analysis.

What we use control assumptions

for, basically, is for units or utilities who do

not provide us with any kind of unit-specific

information.

MR. AYRES: And could you also tell us

the source for the cost estimates for mercury

controls that went into your analysis? You were

talking about technology before.

MR. MARCHETTI: Well.

MR. AYRES: Perhaps it's the same. I

don't know.

MR. MARCHETTI: It's the same. It's

the same.

Basically, what I just said, for

technology, would also apply for mercury

control.

MR. AYRES: And you're not able to

provide to us the details of either the cost or

technology information that you received from

the companies?

L.A. REPORTING (312) 419-9292

1255

MR. MARCHETTI: That's correct.

MR. AYERS: Okay. What did

Dr. Smith's model do with the data, which came

from Mr. Cichanowicz, I guess, to her; is that

correct?

MR. MARCHETTI: I believe she

mentioned that in her testimony that she used

Ed Cichanowicz's cost assumptions.

MR. AYRES: And those would be the

same ones that we just talked about?

MR. MARCHETTI: Yes.

MR. AYRES: And then what did her

model do with that? This is a very complex

series of steps that you've gone through to

produce your report, and I just want to

understand.

MR. MARCHETTI: Yeah. She, basically,

ran a simulation in terms of -- well, let me

just back up.

In terms of Dr. Smith's -- with

what she did with our -- Mr. Cichanowicz's

subjects provided us with inputs, is that what

you're looking for, or are you looking for some

other -- something else that Dr. Smith did?

L.A. REPORTING (312) 419-9292

1256

MR. AYRES: Well, I assume that -- I

think you said that Dr. Cichanowicz's technology

choices and cost numbers were conveyed to

Ms. Smith?

MR. MARCHETTI: Yes.

MR. AYRES: And she ran a model, which

she describes, generally, in her addendum.

MR. MARCHETTI: Okay.

MR. AYRES: And what was the output of

that model that was then the input to your

model?

MR. MARCHETTI: What Dr. Smith

presented us was future generation, coal and oil

gas-fired generation in the state of Illinois,

on a unit-by-unit basis for a CAIR/CAMR scenario

and a CAIR Illinois Rule scenario. She also

presented us with future coal and gas prices,

delivered gas prices, delivered coal and gas

prices for Illinois units.

In this state it was from 2009 to

2020, I believe, for intermittent years. It was

nine, ten, 13, 15 and 18. Those were the dates

we used, so we internally could be in between.

She also provided us with future

L.A. REPORTING (312) 419-9292

1257

SO2, NOx and mercury allowance prices for

CAIR/CAMR and a CAIR Illinois Rule regime.

HEARING OFFICER: Excuse me.

Mr. Ayres, before you go on, could we go off the

record for just a second?

MR. AYRES: Sure.

(WHEREUPON, discussion was had

off the record.)

HEARING OFFICER: We're back on the

record.

And I would note that, the file

that was a part of Mr. Marchetti's testimony is

a document entitled Addendum of Anne E. Smith,

Ph.D. to the testimony Krish Vijayaraghavan and

James Marchetti, and that is a part of their

testimony as a reference document and not a part

of Dr. Smith's testimony, which she presented

earlier in the week.

MR. ZABEL: But the point I think that

Mr. Bonebrake was making off the record is it

was a document prepared by Ms. Smith. And at

the prehearing conference, which I didn't

attend, so I'll let you --

MR. BONEBRAKE: And as, to which, it

L.A. REPORTING (312) 419-9292

1258

was my understanding based upon our conference

call before the hearing, that if there were

questions for Dr. Smith pertaining to her

addendum, those could be directed to her while

she was present earlier this week, as well.

HEARING OFFICER: That is correct.

And, to my knowledge, there were no questions

directed to her directly on the addendum.

MR. BONEBRAKE: I don't recall any.

HEARING OFFICER: But that is correct,

that your recollection and mine at the

prehearing conference is exactly the same.

MR. ZABEL: We attached it to those

testimonies because it's something that both of

the other witnesses relied on.

HEARING OFFICER: Wonderful. Thank

you very much.

MR. AYRES: The two documents that we

received this morning, the CAIR/CAMR and the

CAIR Illinois Rule Tech, those two tables, are

these the output of Dr. Smith's model?

MR. MARCHETTI: No. To be honest,

they are our outputs.

MR. AYRES: They're outputs from your

L.A. REPORTING (312) 419-9292

1259

model?

MR. MARCHETTI: Yes.

MR. AYRES: Okay. So in what way did

you use the output of her model then?

MR. ZABEL: I think he just described

that. I'm happy to have him repeat it.

MR. AYRES: Okay.

MR. MARCHETTI: The only outputs of

Dr. --

MR. ZABEL: Did you want him to go

through that again?

MR. AYRES: No, that's fine.

MR. ZABEL: We'll save some time.

MR. AYRES: On Page 11, you state that

your model predicts that 73 percent of the

capacity, I believe it is, in Illinois, will

install filters, meaning fabric filters, I'm

assuming; is that correct?

MR. MARCHETTI: That would be filter

technologies, kind of a -- for a category, would

be for cold packs, halogenated cold packs and

fabric filters.

MR. AYRES: But all would involve a

baghouse for fabric filters?

L.A. REPORTING (312) 419-9292

1260

MR. MARCHETTI: Yes.

MR. AYRES: So what you've described

is then that Mr. Cichanowicz has developed

technology costs and technologies, which then

were entered into Ms. Smith's model to produce

CAIR/CAMR prediction. And then carried over, in

fact, into your model to produce your comparison

of CAIR and Illinois Rule; correct?

MR. ZABEL: Just to be clear, I think

what Mr. Marchetti described was Ms. Smith's

model -- and correct me if I'm in error -- gave

them future generation under CAMR/CAIR CAIR

Illinois.

MR. AYRES: I said that.

MR. ZABEL: Okay. Well, just to be

clear, what the limit of that was, is the way

you phrased it.

MR. MARCHETTI: Yeah, we did not --

they didn't know CAIR/CAMR and CAIR Illinois

simulations. We would not use any of their

technology deploying the various inputs I

described earlier.

We put them in our model and then

did a compliance analysis there.

L.A. REPORTING (312) 419-9292

1261

MR. AYRES: So would it be fair to say

that the costs and impacts that you predict --

on the Illinois utilities that you predict, are

largely determined by the technical choices and

cost data supplied by Mr. Cichanowicz?

MR. MARCHETTI: Yes. As well as the

unit-specific information that is provided by

the various -- the utilities that I mentioned

before.

MR. AYRES: Which we don't have before

us?

MR. MARCHETTI: Yes.

Question 2.

HEARING OFFICER: Excuse me, Ms. Moore

has a follow-up, I think.

MR. MARCHETTI: Oh, I'm sorry.

MS. MOORE: And I might need some help

with this. This is something that I'm

recollecting.

But with the 1990 Clean Air Act, I

have this recollection that there were certain

older power plants that were grandfathered, and

unless they made a significant improvement, they

could operate without meeting the standards.

L.A. REPORTING (312) 419-9292

1262

Are you familiar with that?

MR. ZABEL: If I may, Ms. Moore, I'd

be happy to -- I mean, it's more of a legal

question, I think, than anything else.

MS. MOORE: Okay.

MR. ZABEL: There were certain

grandfathered provisions in the 1990 amendment,

they don't relate to CAIR at all. Whatever

grandfathering there was in 1990 amendments,

doesn't apply to any sources regulated under

CAIR.

MS. MOORE: Okay.

MR. ZABEL: But they were regulated,

and maybe the question you're getting at is new

source reviews. But if they made certain

modifications under the terms of those

provisions --

MS. MOORE: Then they would have to

meet standards.

MR. ZABEL: -- then they had to

upgrade them.

MS. MOORE: Right.

My question is this: Are any of

those plants still operating? The ones that

L.A. REPORTING (312) 419-9292

1263

were grandfathered in 1990?

MR. ZABEL: Oh, yes, many of them.

Now I'm testifying. That's fact,

not law.

But the fact is, you could look in

the Clean Air Act, it actually lists plants in

Phase I and Phase II, which were all operating

in 1990. You'll find in the statute lots of

plants whose names you're quite familiar with.

MS. MOORE: So the older plants that

were exempted in 1990 are still operating?

MR. ZABEL: Many of them, yes.

MS. MOORE: Okay.

Do you know how many of our

50 year and older ones are still operating?

MR. AYRES: Well, if lawyers can

testify -- based on what I know, almost all of

them.

MS. MOORE: Thank you.

MR. ZABEL: The lawyers agree,

actually.

HEARING OFFICER: Then I think the

point of where Ms. Moore is actually going with

it, too, with the 50 Year Rule, the legal

L.A. REPORTING (312) 419-9292

1264

opinion is that CAIR doesn't apply, what about

the Illinois Rule --

MR. ZABEL: No, CAIR does apply. I'm

sorry.

HEARING OFFICER: Okay. I'm sorry.

MR. ZABEL: If I stated it the other

way, I misstated it.

HEARING OFFICER: So the "50 Year

Rule," as it's called, and I put that in quotes

because that's the language that's been repeated

here, those plants that were initially exempt in

the 1990s are figured into the plants that are

figured into this model; correct?

MR. MARCHETTI: Yes.

HEARING OFFICER: Thank you.

MR. ZABEL: Two.

Oh, I'm sorry, Doctor.

MR. GIRARD: Yeah, I've got a question

then.

So, Mr. Marchetti, did you look at

any of the assumptions that Anne Smith used in

coming up with the price for the mercury

allowances?

MR. MARCHETTI: The assumptions that

L.A. REPORTING (312) 419-9292

1265

she used were based upon assumptions that

Mr. Cichanowicz gave her. And it is mentioned

in discussion in my testimony, and I believe in

my appendix of my testimony, that the FGD cost

assumptions that they used was based upon, I

think, about $300 a KW for an FGD, $200 a KW for

an SCR.

And I believe it also included a

$35 per KW for an activated carbon system, there

was a 250 megawatt activated carbon system with

an SCA of 250, it was $35 a KW. Those were the

control assumptions that Mr. Cichanowicz

provided Dr. Smith for the simulations.

MR. GIRARD: So those are control

assumptions. But how about the assumption of

what it would cost you to purchase an allowance

on the market under CAMR?

MR. MARCHETTI: She calculated those

in her simulations. She calculated the

allowance prices for both CAIR and CAMR.

MR. GIRARD: And do you think -- I

mean, are the assumptions somewhere in

Mr. Cichanowicz's testimony or we just don't

know what they are? I'm trying to understand

L.A. REPORTING (312) 419-9292

1266

how it would calculate numbers for what the

theoretical mercury allowance would cost if you

purchased it from another plant.

MR. MARCHETTI: Yeah. Well, the

allowance prices that Dr. Smith calculated are

presented here in the appendix, my appendix,

Appendix A of the testimony, as well as the

addendum that appears in my testimony from

Dr. Smith. So those are the allowance prices

that we used.

MR. GIRARD: Okay. Well, you know, I

can see that, like on page -- we're looking at

Page 35/35 of your testimony here, I'm looking

at the addendum. But all I see is a spreadsheet

with mercury in dollars per pound by year. So

that's all we have, the calculations made?

MS. BASSI: The title of Table 9 on

the page you're referring to, Page 39, this is

from Dr. Smith's addendum to Mr. Marchetti's

testimony. These are the allowance prices that

were projected in her simulation, from her --

these are the allowance prices that she

developed for NOx, annual NOx and SO2 and

mercury.

L.A. REPORTING (312) 419-9292

1267

So these are the allowance prices

that he -- I'm testifying, I don't want to do

that.

MR. GIRARD: No, I understand that.

And that's what I'm looking at, I'm looking at

that page.

But what I'm trying to find out

is, whose testimony do I look in to find the

assumptions that went into coming up with those

values? So, I mean, there were assumptions made

to be able to come up with figures to put into a

model and spit out values.

MR. MARCHETTI: Yeah.

MR. GIRARD: And, you know, if I can

find that in Mr. Cichanowicz's testimony and

Ms. Smith's testimony --

MR. MARCHETTI: Well, the only way

that it's going to refer to any kind of

assumptions is the control substance to be

provided. And then Dr Smith's model that takes

that as one part -- is one portion of the

information and plugs it in, and then she checks

the allowance prices.

The model doesn't -- there are

L.A. REPORTING (312) 419-9292

1268

other assumptions that go into the model, such

as fuel costs, you know, dispatch order of units

within a range. And so, I mean, it's,

basically, who provided her with just one of the

elements that was used in her projection of the

allowance prices.

MR. GIRARD: Okay. So to understand

it then, we would need to see how the entire

model is constructed, in other words. That's

what you're saying?

MR. MARCHETTI: Well, you would -- you

would -- I mean, it's a projection on their

part, based upon other variables besides, I

believe, the -- I mean, instead of the control

assumptions that we provide. I mean, control

assumptions, certainly, are very critical, in

terms of allowance prices, because they apply to

units.

And using allowance prices, based

upon their marginal cost and control, which is

that last unit that's coming into compliance.

And that's what -- you know, that's usually the

price -- maybe that's just a price setting

format, you know, for allowance price.

L.A. REPORTING (312) 419-9292

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MR. GIRARD: Thank you.

HEARING OFFICER: Mr. Melas.

MR. MELAS: Mr. Marchetti, a slightly

different matter. This 50 Year Rule that you

have here, the lower paragraph, Page 4 --

MR. MARCHETTI: Yes.

MR. MELAS: -- I'm a little curious

about the rule. Is that a nationally

promulgated accepted rule or is that -- it says

here it was MCH fields. Is this something you

developed?

MR. MARCHETTI: Yeah, it's just a

presumption that we've developed that we use.

MCH is -- may pop up as Marchetti Chicago.

MR. MELAS: I see that.

MR. MARCHETTI: Okay.

MR. ZABEL: Would it be better to call

it a rule of thumb, Mr. Marchetti? That's not a

real regulation of any kind.

MR. MARCHETTI: No. It's no legal

regulation. It's not been mandated in any kind

of regulation about putting technology on units,

under 50 or over 50 or any age.

MR. AYRES: But it is a legal rule --

L.A. REPORTING (312) 419-9292

1270

well, forget the word "legal." It is a rule in

your model, though, isn't it?

MR. MARCHETTI: It is a rule in our

model. Specifically we use it when we use a cap

and trade analysis.

MR. AYRES: And which, therefore, has

an impact in determining the output of the

model?

MR. MARCHETTI: Yes.

MR. AYRES: Thank you.

A slightly different topic: You

testified on Page 15 that the ICFs costs tend to

fall between MCH and TSD, between your costs and

those of the technical support document.

However, the ICF report provides very little

information on their assumptions, which make it

difficult to track their findings.

Have you looked at Page 24 of

Dr. Smith's testimony that you include with

yours, the Appendix A, where she describes CRAs,

the model we'll call NEEM?

MR. MARCHETTI: Dr. Smith's testimony?

MR. AYRES: Yes. Page 24 of your

testimony.

L.A. REPORTING (312) 419-9292

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MR. MARCHETTI: Okay.

MR. ZABEL: Do you have a specific

spot on this?

MR. AYRES: The bottom paragraph where

she says, "NEEM is a similar model for the IPM

model that is used extensively by the U.S.EPA

and also has been used by the EPA in this

proceeding. Both models are dynamic linear

programming models of a US electricity sector.

The models both minimize the present value

incremental costs, subject to the set of

operational constraints. The primary difference

between the NEEM and IPM is in the exogenous

assumptions used in the respective models, such

as cost and effectiveness of control

technologies, fuel prices and the electricity

demand levels."

You knew that she wrote this;

didn't you?

MR. MARCHETTI: I'm sorry, could you

repeat?

MR. AYRES: Did you know that she

wrote this?

MR. MARCHETTI: Yes.

L.A. REPORTING (312) 419-9292

1272

MR. AYRES: And you knew that the IPM

model was used by EPA?

MR. MARCHETTI: Yes.

MR. AYRES: And do you think Dr. Smith

was clearly aware of these facts, that the ICF

model was widely used and had been reviewed by

many people?

MR. ZABEL: He's testified that she

wrote it.

MR. AYRES: Right.

MR. ZABEL: So I think, beyond that,

one can presume she knew it. But if you're

asking what's in her mind, I think that's a

difficult question to him.

MR. AYRES: I withdraw the question.

Didn't the ICF report describe the

assumptions regarding how they capped emission

levels at plants?

MR. MARCHETTI: In their analysis,

they talked about their representations, yeah,

how they capped emission levels at points.

MR. AYRES: And that's the way their

model works; isn't it, it places caps on units?

MR. MARCHETTI: It depends on the

L.A. REPORTING (312) 419-9292

1273

regulatory regime that we're looking at. If its

like CAIR, where we did assign allocations for

that particular regime.

In the Illinois Rule, I do have a

response to a question, which I believe is

No. 3, which talks about how we implemented in

the Illinois Rule and how we modeled it.

MR. AYRES: That could help. ICF did

it or --

MR. MARCHETTI: How we did it. I

believe you just asked me how -- if we used

caps, and we do.

MR. AYRES: So the ICF report

described its assumptions, didn't Dr. Staudt

describe his mercury control assumptions in the

TSD?

MR. MARCHETTI: ICF, in terms

describing your assumptions in a report, I don't

believe it was clearly defined in that report

that was a part of the GSD. Dr. Staudt was

presented two tables at the TSD, which had

controlled costs and removals and operation

costs.

MR. ZABEL: In fact, if I may, Madam

L.A. REPORTING (312) 419-9292

1274

Hearing Officer, I recall now going back and

looking at the record, that some of the specific

questions we asked of the agency concerned the

input to the IPF model, but there was no witness

from there tendered who could answer. We got

some generality answers that the agency knew,

we'd never get a table, such as this

(indicating), or specifics on the model that was

used.

MR. AYRES: But the report from ICF

did describe their assumptions on this point;

correct?

MR. MARCHETTI: They described the

implementation of the Illinois Mercury Rules as

best they could interpret at the time. They did

not describe their control subjects.

MR. AYRES: Okay. Would those be on

the EPA website, the Illinois EPA website -- I'm

sorry, the U.S.EPA website?

MR. MARCHETTI: I believe they have

some documentation that's called -- various

years -- I think a couple of years they put out

some documentation on inputs that they used in

the IPM model. They can be found on a Clean Air

L.A. REPORTING (312) 419-9292

1275

or Morton's division website.

MR. AYRES: Do they have cost

assumptions and --

MR. MARCHETTI: They have various cost

assumptions and algorithms there. Some of it is

very difficult to follow.

It's not like you could go to a

table and say this is the dollar per KW for a

500 megawatt unit that's burning bituminous coal

and it has an emission rate of this or that.

It's not that specific.

And you would have to -- sometimes

you have to go read one document and then go

back to a previous version of a document to get

the control assumptions.

MR. AYRES: Well, it's a complex

model, like the NEMS model, and so it comes up

with complex outputs. But my question is about

the inputs, and am I not correct, that the

inputs, that model, are available?

MR. MARCHETTI: The inputs of that

model are available.

MR. AYRES: And are you aware that

Mr. DePriest was unwilling to provide them the

L.A. REPORTING (312) 419-9292

1276

details regarding how he developed processes for

Mr. Cichanowicz?

MR. BONEBRAKE: I think you're

mischaracterizing his testimony, Mr. Ayers, both

in writing and provided here to the Board.

MR. AYRES: I think the Board can be

the judge of that.

You are aware that Mr. DePriest

declined to provide information about his cost

estimates yesterday?

MR. BONEBRAKE: You can clarify and

say some information, Mr. Ayres, perhaps we can

proceed with the question.

MR. AYRES: Some information?

MR. MARCHETTI: Yes. He mentioned

that there was some confidentiality associated

with some of the information that he was

testifying.

MR. AYRES: And you're unable to

provide some of the information that you use to

develop technology assumptions for -- or that

were used to develop the technology assumptions

that went into your model?

MR. MARCHETTI: Yes.

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MR. AYRES: Thank you.

HEARING OFFICER: Question No. 2.

MR. MARCHETTI: On Page 5, you note

the "Capital and operating costs were developed

based upon Illinois generators' experience in

retrofitting recent SO2, NOx and mercury control

technologies." Please identify the experience

to which you refer, specifically with respect to

the installation of mercury control

technologies, and show how that experience was

used to set the control cost parameters used in

the EEMS model.

Several Illinois generators

provided us --

HEARING OFFICER: Slow down,

Mr. Marchetti.

MR. MARCHETTI: Okay.

Several --

MR. AYRES: Please speak up, it's hard

to hear you over here.

MR. MARCHETTI: Okay.

Several Illinois generators

provided us with unit specific capital

operational cost information to retrofit SO2,

L.A. REPORTING (312) 419-9292

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NOx and mercury control technologies. These

costs were applied when considering technology

choices for those specific EGUs.

Additionally, the supplied costs

were used as the basis for estimating technology

costs for other units in the state and did not

supply specific cost information as described in

Appendix A and B of Mr. Cichanowicz's testimony.

HEARING OFFICER: Question No. 3.

MR. MARCHETTI: Please explain

implementation of the proposed rule in the EEMS

model.

The Illinois Rule calls for EGUs

to meet either a percent reduction for coal

input mercury levels or an output emission

standard beginning July 1st, 2009. Since the

proposed rule allows for facility-wide

averaging, annual plant mercury emission limits

were computed for each facility, which acted as

the reduction target each plant would have to

achieve in compliance with the Illinois Rule.

The annual plant limits were

determined by first computing annual plant

limits used in two levels, percent reduction

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from input fuel or emission standards based upon

gross generation. The most lenient of the plant

level limits was selected as the reduction for

the specific plant and year.

It should be noted that the plant

level limits could change from year to year

based upon changes in generation. We then

computed plant balances, which is the difference

between future annual emissions and plant

limits.

These differences were the level

of mercury emissions that had to be removed to

meet the reduction targets of the Illinois Rule.

A. Please describe exactly what

constraints are placed on mercury emissions for

each unit in the model implementation.

I believe the annual plant limits

discussed above answers the question on the --

MR. AYRES: Pardon me, but you said

annual what?

MR. MARCHETTI: I believe the annual

plant limits discussed above -- which would be

the previous question, okay -- answers the

question on the Illinois Rule. However, if

L.A. REPORTING (312) 419-9292

1280

you're asking about a cap and trade approach,

such as CAMR, each unit receives a mercury

allowance allocation as described on Page 18 of

my testimony.

MR. AYRES: The question was about the

Illinois Rule; wasn't it?

MR. ZABEL: I'm sorry, I couldn't hear

you, Mr. Ayres.

MR. AYRES: I'm sorry.

I thought the question was that

the Illinois restraints placed on mercury

emissions in the Illinois model, since it's

explained in the implementation in the rule in

the EEMS -- the rule, proposed rule, in the EEMS

model. Maybe I didn't hear it, but I didn't

hear that explained.

MR. ZABEL: He said specifically that

they calculated the more lenient of the two,

that is, the percent reduction or the point of

0080. Okay?

MR. AYRES: All right.

MR. MARCHETTI: B. Please explain the

decisions made by the model with respect to

least-cost implementation of mercury controls.

L.A. REPORTING (312) 419-9292

1281

To comply with plant level limits for mercury in

the Illinois Rule, the different method is used

to design the removal technology.

Because of a limited number of

units at a facility, a maximum number of six in

these cases, we are able to examine all

combinations of the feasible technology options.

Unit level annual costs and removals are

calculated for all applicable control

technologies for each unit.

The unit-technology combinations

are stored in a two dimensional matrix a

decision-making program goes through each set of

options and totals the removals achieved to

determine if a sufficient amount of mercury will

be removed.

In these analyses, there are six

different retrofit options along with a "no

technology" option for each unit. Many of these

are not applicable, such as the fluidized bed

for COHPAC, steam unit.

But all combinations that are

possible are explored. Each combination that

yields a sufficient removal is stored and sorted

L.A. REPORTING (312) 419-9292

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in the order of increasing cost.

Lastly, the combinations are

examined, least cost option first and the

proscribed combinations are thrown out. Units

at each facility are assumed to avoid mixing

standard carbon injection technology and

halogenated carbon injection options.

Once a satisfactory mix is

encountered in the order list, the units are

assigned that retrofit technology or no tech and

removals and costs are reported.

Another guideline in the decision

is that once a unit is assigned a technology, it

will not be removed or changed in a later year.

In Illinois, there are a relatively unchanging

limits for each facility. So the decision

process starts in the first year of study, where

cobenefits are the lowest and removal needs are

the highest and move forward in time.

For CAMR, a cap and trade approach

is used. For each unit, several technology

options are assigned on a dollar per pound

removal cost and a total annual cost.

Each feasible technology is

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examined against the allowance price for that

year. If the technology's dollar per pound

removal basis is less than the allowance price

or if the total annual cost after netting out

excess allowances generated is less than the

cost of the only allowance purchases, the

technology is considered feasible. Each unit's

decision is simply taking the lowest cost option

among various technologies and purchasing

allowances.

The same restrictions against

mixing sorbents at one facility and against

removing or changing installed technologies at a

unit are imposed.

MR. AYRES: Are you finished?

MR. MARCHETTI: Sure.

MR. AYRES: I take it that the 50 Year

Rule is also applied with respect to the

calculation of the CAIR/CAMR case; is that

correct?

MR. MARCHETTI: That's correct.

No. 4 --

HEARING OFFICER: If we're done with

3, I have almost 20 to 1:00, and I think we have

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1284

a different court reporter coming back this

afternoon. So this is probably a good time to

take a lunch break and give me an opportunity to

look at the materials given out earlier.

And everybody be back in about an

hour.

(WHEREUPON, a recess was had.)

L.A. REPORTING (312) 419-9292

1285

1 STATE OF ILLINOIS)

) SS:

3 COUNTY OF COOK )

I, SHARON BERKERY, a Certified Shorthand

5 Reporter of the State of Illinois, do hereby certify

6 that I reported in shorthand the proceedings had at

7 the hearing aforesaid, and that the foregoing is a

8 true, complete and correct transcript of the

9 proceedings of said hearing as appears from my

10 stenographic notes so taken and transcribed under my

11 personal direction.

IN WITNESS WHEREOF, I do hereunto set my

13 hand at Chicago, Illinois, this 23rd day of

14 August, 2006.

Certified Shorthand Reporter

19 C.S.R. Certificate No. 84-4327.

L.A. REPORTING (312) 419-9292